10-K 1 noblecorpplc-201710xk.htm 10-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________________________________________
FORM 10-K
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to             
Commission file number: 001-36211
_____________________________________________________________________________________________________
Noble Corporation plc
(Exact name of registrant as specified in its charter)
England and Wales (Registered Number 08354954)
 
98-0619597
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. employer
identification number)
Devonshire House, 1 Mayfair Place, London, England, W1J8AJ
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: +44 20 3300 2300
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Shares, Nominal Value $0.01 per Share
 
New York Stock Exchange
Commission file number: 001-31306
_____________________________________________________________________________________________________
Noble Corporation
(Exact name of registrant as specified in its charter)
Cayman Islands
 
98-0366361
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. employer
identification number)
Suite 3D Landmark Square, 64 Earth Close, P.O. Box 31327 George Town, Grand Cayman, Cayman Islands, KY1-1206
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: (345) 938-0293
Securities registered pursuant to Sections 12(b) and 12(g) of the Act: None
_______________________________________________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ   No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.    Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Noble Corporation plc:
Large accelerated filer þ
Accelerated filer ¨
Non-accelerated filer ¨
Smaller reporting company ¨
Emerging growth company ¨
Noble Corporation:
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer þ
Smaller reporting company ¨
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ¨
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ
As of June 30, 2017, the aggregate market value of the registered shares of Noble Corporation plc held by non-affiliates of the registrant was $876.0 million based on the closing sale price as reported on the New York Stock Exchange.
Number of shares outstanding and trading at February 20, 2018: Noble Corporation plc — 246,776,217
Number of shares outstanding: Noble Corporation — 261,245,693
DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement for the 2018 annual general meeting of the shareholders of Noble Corporation plc will be incorporated by reference into Part III of this Form 10-K.
This Form 10-K is a combined annual report being filed separately by two registrants: Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), and its wholly-owned subsidiary, Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Noble-Cayman meets the conditions set forth in General Instructions I(1)(a), (b) and (d) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format contemplated by General Instructions I(2)(a) and (c) of Form 10-K.

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TABLE OF CONTENTS
 
 
 
 
 
Page
PART I
 
 
 
 
Item 1.
 
 
4 
Item 1A.
 
 
10 
Item 1B.
 
 
Item 2.
 
 
Item 3.
 
 
Item 4.
 
 
 
 
 
 
 
PART II
 
 
 
 
Item 5.
 
 
25 
Item 6.
 
 
Item 7.
 
 
Item 7A.
 
 
Item 8.
 
 
Item 9.
 
 
Item 9A.
 
 
Item 9B.
 
 
 
 
 
 
 
PART III
 
 
 
 
Item 10.
 
 
Item 11.
 
 
Item 12.
 
 
105 
Item 13.
 
 
Item 14.
 
 
 
 
 
 
 
PART IV
 
 
 
Item 15.
 
 
Item 16.
 
 
 
 
 
 
 
 
 
 
This combined Annual Report on Form 10-K is separately filed by Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), and Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Information in this filing relating to Noble-Cayman is filed by Noble-UK and separately by Noble-Cayman on its own behalf. Noble-Cayman makes no representation as to information relating to Noble-UK (except as it may relate to Noble-Cayman) or any other affiliate or subsidiary of Noble-UK.
This report should be read in its entirety as it pertains to each Registrant. Except where indicated, the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements are combined. References in this Annual Report on Form 10-K to “Noble,” the “Company,” “we,” “us,” “our” and words of similar meaning refer collectively to Noble-UK and its consolidated subsidiaries, including Noble-Cayman.



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Forward-Looking Statements
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, (the “Exchange Act”). All statements other than statements of historical facts included in this report or in the documents incorporated by reference, including those regarding rig demand, the offshore drilling market, oil prices, contract backlog, fleet status, our future financial position, business strategy, impairments, repayment of debt, credit ratings, borrowings under our Credit Facilities (as defined herein) or other instruments, sources of funds, future capital expenditures, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation, audit or investigation, plans and objectives of management for future operations, foreign currency requirements, results of joint ventures, indemnity and other contract claims, reactivation, refurbishment, conversion and upgrade of rigs, industry conditions, access to financing, impact of competition, governmental regulations and permitting, availability of labor, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, dividends and distributable reserves, timing or results of acquisitions or dispositions, and timing for compliance with any new regulations are forward-looking statements. When used in this report or in the documents incorporated by reference, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. Actual results could differ materially from those expressed as a result of various factors. These factors include those referenced or described under “Risk Factors” included in this report, or in our other SEC filings, among others. Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks when you are evaluating us.

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PART I
Item 1. Business.
Overview
Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services with our global fleet of mobile offshore drilling units. We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world. As of February 20, 2018, our 28-rig fleet consisted of eight drillships, six semisubmersibles and 14 jackups.
For additional information on the specifications of our fleet, see Part I, Item 2, “Properties— Drilling Fleet.” At December 31, 2017, our fleet was located in Canada, Far East Asia, the Middle East, the North Sea, Oceania, South America and the Gulf of Mexico. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.
Noble Corporation, a Cayman Islands company (“Noble-Cayman”), is an indirect, wholly-owned subsidiary of Noble-UK, our publicly-traded parent company. Noble-UK’s principal asset is all of the shares of Noble-Cayman. Noble-Cayman has no public equity outstanding. The consolidated financial statements of Noble-UK include the accounts of Noble-Cayman, and Noble-UK conducts substantially all its business through Noble-Cayman and its subsidiaries.
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the “Spin-off”) through a pro rata distribution of all the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (“Paragon Offshore”), to the holders of Noble’s ordinary shares. Our shareholders received one share of Paragon Offshore for every three shares of Noble owned as of July 23, 2014, the record date for the distribution. Through the Spin-off, we disposed of most of our standard specification drilling units and related assets, liabilities and business. Prior to the Spin-off, Paragon Offshore issued approximately $1.7 billion of long-term debt, the proceeds of which were used to repay certain amounts outstanding under our commercial paper program. The results of operations for Paragon Offshore prior to the Spin-off date and incremental Spin-off related costs have been classified as discontinued operations for all periods presented in this Annual Report on Form 10-K.
For additional information regarding the Spin-off and our current relationship with Paragon Offshore, see Part I, Item 1A, "Risk Factors" and Part II, Item 8, “Financial Statements and Supplementary Data, Note 14— Commitments and Contingencies.”
Business Strategy
Our goal is to be the preferred offshore drilling contractor for the oil and gas industry based upon the following core principles:
operate in a manner that provides a safe working environment for our employees and contractors while protecting the environment and our assets;
provide an attractive investment vehicle; and
deliver superior customer service through a diverse and technically advanced fleet operated by proficient crews.
Our business strategy focuses on a balanced, high-specification fleet of floating and jackup rigs and the deployment of our drilling rigs in oil and gas basins around the world.
We have expanded our drilling and fleet through our newbuild program. We took delivery of our last remaining newbuild, the heavy-duty, harsh environment jackup, the Noble Lloyd Noble, in July 2016. The Noble Lloyd Noble commenced operations in November 2016 under a four-year contract in the North Sea. Although we plan to prioritize capital preservation and liquidity based on current market conditions, from time to time we will also continue to evaluate opportunities to enhance our fleet, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required by our customers.
Drilling Services
We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:
contract duration extending over a specific period of time or a period necessary to drill a defined number wells;
payment of compensation to us (generally in U.S. Dollars although some customers, typically national oil companies, require a part of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of

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equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control);
provisions permitting early termination of the contract by the customer (i) if the unit is lost or destroyed or (ii) if operations are suspended for a specified period of time due to breakdown of equipment or breach of contract;
provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time;
payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies;
provisions that allow us to recover certain cost increases from our customers in certain long-term contracts; and
provisions that require us to lower dayrates for documented cost decreases in certain long-term contracts.
The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts and, in certain cases, without any payment.
Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to assume these costs, our operating margins are reduced accordingly. For shorter moves, such as “field moves,” our customers have generally agreed to assume the costs of moving the unit in the form of a reduced dayrate or “move rate” while the unit is being moved. Under current market conditions, we are much less likely to receive full reimbursement of our mobilization and demobilization costs.
During periods of depressed market conditions, such as the one we are currently experiencing, our customers may attempt to renegotiate or repudiate their contracts with us although we seek to enforce our rights under our contracts. The renegotiations may include changes to key contract terms, such as pricing, termination and risk allocation. 
For a discussion of our backlog of commitments for contract drilling services, please read Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Contract Drilling Services Backlog.”
Significant Customers
Offshore contract drilling operations accounted for approximately 98 percent of our operating revenues for the years ended December 31, 2017, 2016 and 2015. During the three years ended December 31, 2017, we principally conducted our contract drilling operations in Canada, Far East Asia, the Middle East, the North Sea, Oceania, South America and the Gulf of Mexico. Revenues from Royal Dutch Shell plc (“Shell”), Statoil ASA (“Statoil”) and Saudi Arabian Oil Company (“Saudi Aramco”) accounted for approximately 45.0 percent, 13.2 percent, and 11.4 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2017. Revenues from Shell and Freeport-McMoRan Inc. (“Freeport”) accounted for approximately 37.5 percent and 24.5 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2016. Revenues from Shell and Freeport accounted for approximately 49.0 percent and 14.2 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2015. No other customer accounted for more than 10 percent of our consolidated operating revenues in 2017, 2016 or 2015.
On May 10, 2016, Freeport, Freeport-McMoRan Oil & Gas LLC and one of our subsidiaries entered into an agreement terminating the contracts on the Noble Sam Croft and the Noble Tom Madden (“FCX Settlement”), which were scheduled to end in July 2017 and November 2017, respectively. During 2016, we recognized approximately $393.0 million in “Contract drilling services revenue” associated with the FCX Settlement. Excluding the $393.0 million of revenue attributable to the FCX Settlement our primary customers during 2016 would have been Shell, Anadarko Petroleum Corporation and Freeport, accounting for approximately 45.0 percent, 11.0 percent and 9.0 percent of our consolidated operation revenues, respectively.
Market
Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world. We may mobilize our drilling rigs between regions for a variety of reasons, including to respond to customer contracting requirements or capture demand in another locale. Demand for our services is, in significant part, a function of the worldwide demand for oil and gas and the global supply of mobile offshore drilling units. In recent years, there has been a significant increase in the number of units, while crude oil prices have declined from approximately $112 per barrel for Brent crude on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to $65 per barrel on February 20, 2018. Our customers have greatly reduced their exploration and development spending and the number of rigs they have under contract since 2014. This combination of increased supply of drilling rigs and reduced demand for such rigs has resulted in falling dayrates and significantly reduced opportunities to re-contract our rigs upon expiry of existing contracts.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by large capital expenditures and high operating and maintenance costs. We compete with other providers of offshore drilling rigs, and some of our competitors may have access to greater financial resources than we do.

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In the provision of contract drilling services, competition involves numerous factors. Price competition, rig availability, location and rig suitability and technical specifications are the primary factors in determining which contractor is awarded a job, although other factors are important, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. In addition to having one of the newest fleets in the industry among our peer companies, we follow a policy of keeping our equipment well-maintained and technologically competitive. However, our rigs could be made obsolete by the development of new techniques and equipment, regulations or customer preferences.
We compete on a worldwide basis, but competition may vary by region. Demand for offshore drilling equipment also depends on the exploration and development programs of oil and gas companies, which in turn are influenced by many factors, including the price of oil and gas, the financial condition of such companies, general global economic conditions, energy demand, political considerations and national oil and gas policy, many of which factors are beyond our control. In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. While we do not anticipate this being an issue in the current market environment, we cannot assure that any such shortages experienced in the past will not happen again in the future.
Employees
At December 31, 2017, we had approximately 2,000 employees, excluding approximately 600 persons we engaged through labor contractors or agencies. Approximately 83 percent of our workforce is located offshore. We are not a party to any material collective bargaining agreements, and we consider our employee relations to be satisfactory.
We place considerable value on the involvement of our employees and maintain a practice of keeping them informed on matters affecting them, as well as on the performance of the Company. Accordingly, we conduct formal and informal meetings with employees, maintain a Company intranet website with matters of interest, issue periodic publications of Company activities and other matters of interest, and offer a variety of in-house training, including through NobleAdvances, our state of the art training facility in Sugar Land, Texas.
We are committed to a policy of recruitment and promotion based upon merit without discrimination. Management actively pursues both the employment of disabled persons whenever a suitable vacancy arises and the continued employment and retraining of employees who become disabled while employed by the Company. Training and development is undertaken for all employees, including disabled persons.
Governmental Regulations and Environmental Matters
Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Our contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, environmental discharges and related recordkeeping, safety management systems, the reduction of greenhouse gas emissions to address climate change, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees, content and suppliers by foreign contractors. A number of countries actively regulate and control the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government actions, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to contribute to oil price volatility. In some areas of the world, this government activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for offshore drilling services, and likely will continue to do so.
The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. Many of the countries in whose waters we operate from time to time regulate the discharge of oil and other contaminants in connection with drilling and marine operations. Failure to comply with these laws and regulations, or failure to obtain or comply with permits, may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. We are also subject to a plea agreement with the U.S. Department of Justice (“DOJ”) in connection with prior operations in Alaska, and any future environmental incidents could have an impact on the plea agreement or related actions that the DOJ or other regulatory agencies may take against us as a result of such an incident. We were granted our motion to terminate the Alaska plea agreement effective March 1, 2018. We have made, and will continue to make, expenditures to comply with environmental requirements. We do not believe that our compliance with such requirements will have a material adverse effect on our results of operations, our competitive position or materially increase our capital expenditures. Although these requirements impact the oil and gas and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry. However, our business and prospects could be adversely affected by regulatory activity that prohibits or restricts our customers’ exploration and production activities, results in reduced demand for our services or imposes environmental protection requirements that result in increased costs to us, our customers or the oil and natural gas industry in general.

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The following is a summary of some of the existing laws and regulations that apply in the United States and Europe, which serves as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate.
Spills and Releases. The Comprehensive Environmental Response, Compensation, and Liability Act in the U.S. (“CERCLA”), and similar state and foreign laws and regulations, impose joint and several liabilities, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” However, we have to-date not received any notification that we are, or may be, potentially responsible for cleanup costs under CERCLA.
Offshore Regulation and Safety. In response to the Macondo well blowout incident in April 2010, the U.S. Department of Interior, through the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), has undertaken an aggressive overhaul of the offshore oil and natural gas regulatory process that has significantly impacted oil and gas development in the U.S. Gulf of Mexico. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress that materially limit or prohibit, and increase the cost of, offshore drilling. We are also subject to the Ports and Waterways Safety Act (“PWSA”) and similar regulations, which impose certain operational requirements on offshore rigs operating in the U.S. and governs liability for vessel or cargo loss, or damage to life, property, or the marine environment. See “Risk Factors-Risk Factors Relating to Our Business-Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations” for additional information.
The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and similar regulations, including but not limited to the International Convention for the Prevention of Pollution from Ships (“MARPOL”), adopted by the International Maritime Organization (“IMO”), as enforced in the United States through the domestic implementing law called the Act to Prevent Pollution from Ships, impose certain operational requirements on offshore rigs operating in the U.S. and govern liability for leaks, spills and blowouts involving pollutants. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located.
Regulations under OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.
Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and similar state, local and foreign laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. As a result, our operations generate minimal quantities of RCRA hazardous wastes. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of this or similar exemption in similar state statutes, would increase the volume of hazardous waste we are required to manage and dispose of, and would cause us, as well as our competitors, to incur increased operating expenses with respect to our U.S. operations.
Water Discharges. The U.S. Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and similar state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water. In addition, the U.S. Coast Guard has promulgated requirements for ballast water management as well as supplemental ballast water requirements, which include limits applicable to specific discharge streams, such as deck runoff, bilge water and gray water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.
Air Emissions. The U.S. Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Climate Change. There is increasing attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”) emissions. The United States Environmental Protection Agency (“EPA”) regulates the permitting of GHG emissions from stationary sources under the Clean

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Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs, which require the use of “best available control technology” for GHG emissions from new and modified major stationary sources, which can sometimes include drillships. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore and offshore oil and natural gas production facilities, on an annual basis.
Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all countries that had ratified it. In 2015, the United Nations Climate Change Conference in Paris resulted in the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. Incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas. See “Risk Factors— Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity” for additional information.
Countries in the European Union (“EU”) implement the U.N.’s Kyoto Protocol on GHG emissions through the Emissions Trading System (“ETS”), though ETS will continue to require GHG reductions in the future that are not currently prescribed by the Kyoto Protocol or related agreements. The ETS program establishes a GHG “cap and trade” system for certain industry sectors, including power generation at some offshore facilities. Total GHG from these sectors is capped, and the cap is reduced over time to achieve a 21 percent GHG reduction from these sectors between 2005 and 2020.
In addition, the United Kingdom (“UK”) government, which implements ETS in the UK North Sea, has introduced a carbon price floor mechanism to place an incrementally increasing minimum price on carbon. Thus, the cost of compliance with ETS can be expected to increase over time. Additional member state climate change legislation may result in potentially material capital expenditures.
We have determined that combustion of diesel fuel (Scope 1) aboard all of our vessels worldwide is the Company’s primary source of GHG emissions, including carbon dioxide, methane and nitrous oxide. The data necessary to report indirect emissions from generation of purchased power (Scope 2) has not been previously collected. We will establish the necessary procedures to collect and report Scope 2 data.
For the year ended December 31, 2017, our estimated carbon dioxide equivalent (“CO2e”) gas emissions were 918,439 tonnes as compared to 985,384 tonnes for the year ended December 31, 2016. When expressed as an intensity measure of tonnes of CO2e gas emissions per dollar of contract drilling revenues from continuing operations, the intensity measure for December 31, 2017 and 2016 was .0008 and .0004, respectively. The increase in emissions is due to the Noble Lloyd Noble operating for the full year of 2017, as well as the Noble Tom Madden and Noble Sam Croft activating and now include helicopter emissions.
Our Scope 1 CO2e gas emissions reporting has been prepared with reference to the requirements set out in the UK Companies Act 2006 Regulations 2013, the Environmental Reporting Guidelines (June 2013) issued by the Department for Environment Food & Rural Affairs, the World Resources Institute and World Business Council for Sustainable Development GHG Protocol Corporate Accounting and Reporting Standard Revised and the International Organization for Standardization (“ISO”) 14064-1, “Specification with guidance at the organizational level for quantification and reporting of greenhouse gas emissions and removals (2006).” We have used SANGEA™ Emissions Estimation Software to estimate CO2e gas of Scope 1 emissions based on diesel fuel consumption.
It is our intent to have the procedures related to GHG emissions independently assessed in the future.
Worker Safety. The U.S. Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. EU member states have also adopted regulations pursuant to EU Directive 2013/30/EU, on the safety of offshore oil and gas operations within the exclusive economic zone (which can extend up to 200 nautical miles from a coast) or the continental shelf. We believe that we are in substantial compliance with OSHA requirements and EU directive 2013/30/EU (as well as the extensive current health and safety regimes implemented in the member states in which we operate), but future developments could require the Company to incur significant costs to comply with the directive's implementation.
International Regulatory Regime. The IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.
The IMO has also adopted MARPOL, including Annex VI to MARPOL which sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. The IMO has also negotiated international conventions that

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impose liability for oil pollution in international waters and the territorial waters of the signatory to such conventions such as the Ballast Water Management Convention, (the “BWM Convention”) and the International Convention for Civil Liability for Bunker Oil Pollution Damage of 2001 (the “Bunker Convention”). The BWM Convention's implementing regulations call for a phased introduction of mandatory ballast of water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. We believe that all of our drilling rigs are currently compliant in all material respects with these regulations. However, the IMO continues to review and introduce new regulations. It is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.
Insurance and Indemnification Matters
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires, collisions, groundings, punch-throughs, and damage or loss from adverse weather and sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties and fines and penalties.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, generally irrespective of the fault or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment. Also, we generally obtain a mutual waiver of consequential losses in our drilling contracts.
Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage. In the current market, we are under increasing pressure to accept exceptions to the above-described allocations of risk and, as a result, take on more risk. In such cases where we agree, we generally limit the exposure with a monetary cap and other restrictions.
In addition to the contractual indemnities described above, we also carry Protection and Indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third-party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our P&I insurance program is renewed in April of each year and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million. We also carry hull and machinery insurance that protects us against physical loss or damage to our drilling rigs, subject to a deductible that is currently $25 million.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face” included in Part I, Item 1A, “Risk Factors” of this Annual Report on Form 10-K.
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report, and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Financial Information about Segments and Geographic Areas
Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is presented in Part II, Item 8, “Financial Statements and Supplementary Data, Note 15— Segment and Related Information.” Information regarding our risks attendant to foreign operations and our dependence upon such foreign operations is presented in Part I, Item 1A, “Risk Factors— We are exposed to risks relating to operations in international locations.”
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 are available free of charge at our website at http://www.noblecorp.com. These filings are also available to the public at the U.S. Securities and Exchange Commission’s (the “SEC”) Public Reference

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Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC’s website at http://www.sec.gov.
You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:
Articles of Association;
Code of Business Conduct and Ethics;
Corporate Governance Guidelines;
Audit Committee Charter;
Compensation Committee Charter;
Health, Safety, Environment and Engineering Committee Charter;
Nominating and Corporate Governance Committee Charter; and
Finance Committee Charter.

Item 1A. Risk Factors.
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could affect our business, operating results and financial condition, as well as affect an investment in our shares.
Our business and results of operations have been materially hurt and our enterprise value has substantially declined due to current depressed market conditions which are the result of the dramatic drop in the oil price and the oversupply of offshore drilling rigs.
Crude oil prices have declined from approximately $112 per barrel for Brent crude on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to approximately $65 per barrel on February 20, 2018. In addition, a large number of offshore drilling rigs were constructed and added to the global fleet in the last few years, and a substantial number of additional rigs, including rigs built on speculation, are available and could enter the market in 2018. Also, many in our industry extended the lives of older rigs rather than retiring these rigs. These factors have led to a significant oversupply of drilling rigs at the same time that our customers have greatly reduced their planned exploration and development spending in response to the depressed price of oil. These factors have affected market conditions and led to a material decline in the demand for our services, the dayrates we are paid by our customers and the level of utilization of our drilling rigs. These poor market conditions, in turn, have led to a material deterioration in our results of operations. We have already experienced a substantial decline in the price of our shares, which has declined from $27 on August 4, 2014 post Spin-off to $4 at February 20, 2018. While the offshore contract drilling industry is highly cyclical and has experienced periods of low demand and higher demand, there can be no assurance as to when or to what extent the current depressed market conditions, and our business, results of operations or enterprise value, will improve. Further, even if the price of oil and gas were to increase dramatically, we cannot assure you that there would be any increase in demand for our services.
Our business depends on the level of activity in the oil and gas industry. Adverse developments affecting the industry, including a decline in the price of oil or gas, reduced demand for oil and gas products and increased regulation of drilling and production, could have a material adverse effect on our business, financial condition and results of operations.
Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration and development and production markets worldwide. As noted above, the price of oil and gas, and market expectations of potential changes in the price, significantly affect this level of activity, as well as dayrates which we can charge customers for our services. However, higher prices do not necessarily translate into increased drilling activity because our clients’ expectations of future commodity prices typically drive demand for our rigs. The price of oil and gas and the level of activity in offshore oil and gas exploration and development are extremely volatile and are affected by numerous factors beyond our control, including:
the cost of exploring for, developing, producing and delivering oil and gas;
the ability of OPEC to set and maintain production levels and pricing;
expectations regarding future energy prices;
increased supply of oil and gas resulting from onshore hydraulic fracturing activity and shale development;
worldwide production and demand for oil and gas, which are impacted by changes in the rate of economic growth in the global economy;
potential acceleration in the development, and the price and availability, of alternative fuels;
the level of production in non-OPEC countries;
worldwide financial instability or recessions;
regulatory restrictions or any moratorium on offshore drilling;

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the discovery rate of new oil and gas reserves either onshore or offshore;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
oil refining capacity;
the ability of oil and gas companies to raise capital;
worldwide instability in the financial and credit sectors and a reduction in the availability of liquidity and credit;
the relative cost of offshore oil and gas exploration versus onshore oil and gas production;
advances in exploration, development and production technology either onshore or offshore;
technical advances affecting energy consumption, including the displacement of hydrocarbons through increasing transportation fuel efficiencies;
merger and divestiture activity among oil and gas producers;
the availability of, and access to, suitable locations from which our customers can produce hydrocarbons;
adverse weather conditions, including hurricanes, typhoons, winter storms and rough seas;
tax laws, regulations and policies;
laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;
the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism; and
the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in the price of oil and gas from their current levels or the failure of the price of oil and gas to recover to a level that encourages our clients to expand their capital spending, a global recession, reduced demand for oil and gas products, increased supply due to the development of new onshore drilling and production technologies, and increased regulation of drilling and production, particularly if several developments were to occur in a short period of time, would have a material adverse effect on our business, financial condition and results of operations. The current downturn has had a material adverse effect on demand for our services since 2015 and is expected to continue to have a material adverse effect on our business and results of operations.
The contract drilling industry is a highly competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be materially reduced.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and operating costs and evolving capability of newer rigs. Drilling contracts are traditionally awarded on a competitive bid basis. Price competition, rig availability, location and rig suitability and technical specifications are the primary factors in determining which contractor is awarded a job, although other factors are important, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. If current competitors, or new market entrants, implement new technical capabilities, services or standards that are more attractive to our customers or price their product offerings more competitively, it could have a material adverse effect on our business, financial condition and results of operations.
In addition to intense competition, our industry has historically been cyclical. The contract drilling industry is currently in a period characterized by low demand for drilling services and excess rig supply. Periods of low demand or excess rig supply intensify the competition in the industry and have resulted in, and are expected to continue to result in, many of our rigs being idle or earning substantially lower dayrates for long periods of time. We cannot provide you with any assurances as to when such period will end, or when there will be higher demand for contract drilling services or a reduction in the number of drilling rigs.
The over-supply of rigs is contributing to a reduction in dayrates and demand for our rigs, which reduction may continue for some time and, therefore, is expected to further adversely impact our revenues and profitability.
Prior to the current downturn, we experienced an extended period of high utilization and high dayrates, and industry participants materially increased the supply of drilling rigs by building new drilling rigs, including some that have not yet entered service. This increase in supply, combined with the decrease in demand for drilling rigs resulting from the substantial decline in the price of oil that began in late 2014, has resulted in an oversupply of drilling rigs, which has contributed to the decline in utilization and dayrates.
We are currently experiencing competition from newbuild rigs that have either already entered the market or are available to enter the market. The entry of these rigs into the market has resulted in lower dayrates for both newbuilds and existing rigs rolling off their current contracts. Lower utilization and dayrates have adversely affected our revenues and profitability and may continue to do so for some time in the future. In addition, our competitors may relocate rigs to geographic markets in which we operate, which could exacerbate excess rig supply and result in

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lower dayrates and utilization in those markets. To the extent that the drilling rigs currently under construction or on order do not have contracts upon their completion, there may be increased price competition as such vessels become operational, which could lead to a further reduction in dayrates and in utilization, and we may be required to idle additional drilling rigs. As a result, our business, financial condition and results of operations would be materially adversely affected.
We may record impairment charges on property and equipment, including rigs and related capital spares.
We evaluate the impairment of property and equipment, which include rigs and related capital spares, whenever events or changes in circumstances (including a decision to cold stack, retire or sell rigs) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future. In addition, we may also take an impairment loss on capital spares and other capital equipment when we deem the value of those items has declined due to factors like obsolescence, deterioration or damage. For example, based upon our impairment analysis as of the years ended December 31, 2017 and 2016, we decided that we would no longer market certain rigs. In connection with these decisions, we recorded impairment charges of $121.6 million and $285.0 million, respectively, on these rigs and certain capital spares during those periods. There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist.
We may not be able to renew or replace expiring contracts, and our customers may terminate or seek to renegotiate or repudiate our drilling contracts or may have financial difficulties which prevents them from meeting their obligations under our drilling contracts.
We had a number of customer contracts that expired in 2016 and 2017 and will expire in 2018. Generally speaking we were not able to renew or replace contracts that expired in 2016 and 2017 on as favorable terms as our previous contracts, if at all, and our ability to renew contracts that expire in 2018 or obtain new contracts and the terms of any such contracts will depend on market conditions and our customers' expectations and assumptions of future oil prices and other factors. During 2016 and 2017, a number of oil and gas companies, including some of our customers, publicly announced significant reductions in their planned exploration and development spending affecting the offshore market, and some of our customers may continue to do so in 2018. These reductions in spending by our customers could further reduce the demand for contract drilling services and as a result, our business, financial condition and results of operations would be materially adversely affected.
Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after a specified notice period by tendering contractually specified termination amounts and, in some cases, without any payment. These termination payments, if any, may not fully compensate us for the loss of a contract. The early termination of a contract may result in a rig being idle for an extended period of time and a reduction in our contract backlog and associated revenue, which could have a material adverse effect on our business, financial condition and results of operations.
In addition, during periods of depressed market conditions, such as the one we are currently experiencing, we are subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts. The ability of our customers to perform their obligations under drilling contracts with us may also be adversely affected by the financial condition of the customer, restricted credit markets, economic downturns and industry downturns. We may elect to renegotiate the rates we receive under our drilling contracts downward if we determine that to be a reasonable business solution. If our customers cancel or are unable to perform their obligations under their drilling contracts, including their payment obligations, and we are unable to secure new contracts on a timely basis on substantially similar terms or if we elect to renegotiate our drilling contracts and accept terms that are less favorable to us, it could have a material adverse effect on our business, financial condition and results of operations.
Our current backlog of contract drilling revenue may not be ultimately realized.
Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments under letters of intent or award for which definitive agreements have not yet been, but are expected to be, executed. We may not be able to perform under these contracts as a result of operational or other breaches or due to events beyond our control, and we may not be able to ultimately execute a definitive agreement in cases where one does not currently exist. Moreover, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us or that they will not seek to renegotiate or repudiate their contracts, especially during the current industry downturn. In estimating backlog, we make certain assumptions about applicable dayrates for our longer-term contracts with dayrate adjustment mechanisms (like certain of our contracts with Shell). While we believe these assumptions are appropriate, we cannot assure you that actual results will mirror these assumptions. Our inability to perform under our contractual obligations or to execute definitive

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agreements, our customers’ inability or unwillingness to fulfill their contractual commitments to us, including as a result of contract repudiations or our decision to accept less favorable terms on our drilling contracts, or the failure of actual results to reflect the assumptions we use to estimate backlog for certain contracts, may have a material adverse effect on our business, financial condition and results of operations.
We are substantially dependent on several of our customers, including Shell, Statoil and Saudi Aramco, and the loss of any of these customers would have a material adverse effect on our financial condition and results of operations.
Any concentration of customers increases the risks associated with any possible termination or nonperformance of drilling contracts, failure to renew contracts or award new contracts or reduction of their drilling programs. Shell, Statoil and Saudi Aramco accounted for approximately 45 percent, 13 percent and 11 percent, respectively, of our consolidated operating revenues and approximately 58 percent, 14 percent and 19 percent, respectively, of our backlog for the year ended December 31, 2017. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts, in addition to our exposure to credit risk. If any of these customers were to terminate or fail to perform their obligations under their contracts and we were not able to find other customers for the affected drilling units promptly, our financial condition and results of operations could be materially adversely affected.

Paragon Offshore has formed and funded a litigation trust as part of its bankruptcy proceedings and the litigation trust has filed claims against us and certain of our officers and directors. In addition, Paragon Offshore has rejected in the bankruptcy proceedings certain separation agreements entered into with us, and as a result, we will be responsible for those liabilities for which we would have otherwise sought indemnification under the separation agreements.

In August 2014, we completed the Spin-off of a majority of our standard specification offshore drilling business through a pro rata distribution of all of the ordinary shares of our wholly-owned subsidiary, Paragon Offshore, to the holders of our ordinary shares. In April 2017, Paragon Offshore filed a bankruptcy plan (the “Plan”). The Plan, which was modified in May 2017, provided for the creation of a litigation trust to which Paragon Offshore transferred its claims against us, including claims of alleged fraudulent conveyance in connection with the Spin-off and the funding of the trust by Paragon Offshore with $10.0 million. The litigation trust is entitled to pursue those claims against us. In June 2017, the revised Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.

On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy. The complaint alleges claims of alleged actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. If any of the litigation trust’s claims are successful, or if we elect to settle any claims, any damages or other amounts we would be required to or agree to pay could have a material adverse effect on our business, financial condition and results of operations. The litigation is in the very early stages, no schedule has been established, and we are not able to predict when, or if, the matters will go to trial or otherwise be concluded. We may be required to establish reserves on our financial statements in advance of the conclusion of the litigation. Such reserves may be substantial and could have a material adverse effect on our financial condition as presented in such financial statements.

We entered into certain separation agreements with Paragon Offshore at the time of the Spin-off (including the master separation agreement, tax sharing agreement, transition services agreement and transition services agreement relating to our operations offshore Brazil) under which we agreed to indemnify Paragon Offshore for certain liabilities, and Paragon Offshore agreed to indemnify us for certain liabilities. As part of the Plan, Paragon Offshore rejected all of these contracts. Accordingly, we are no longer entitled to seek indemnity from Paragon Offshore under such agreements, and we would be responsible for those liabilities for which we would have otherwise sought indemnification. Such liabilities could have a material adverse effect on our business, financial condition and results of operations.
Our business involves numerous operating hazards.
Our operations are subject to many hazards inherent in the drilling business, including:
well blowouts;
fires;
collisions or groundings of offshore equipment and helicopter accidents;
punch-throughs;
mechanical or technological failures;
failure of our employees or third-party contractors to comply with our internal environmental, health and safety guidelines;
pipe or cement failures and casing collapses, which could release oil, gas or drilling fluids;
geological formations with abnormal pressures;
loop currents or eddies;

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failure of critical equipment;
toxic gas emanating from the well;
spillage handling and disposing of materials; and
adverse weather conditions, including hurricanes, typhoons, tsunamis, winter storms and rough seas.
These hazards could cause personal injury or loss of life, suspend drilling operations, result in regulatory investigation or penalties, seriously damage or destroy property and equipment, result in claims by employees, customers or third parties, cause environmental damage and cause substantial damage to oil and gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. The occurrence of any of the hazards we face could have a material adverse effect on our business, financial condition and results of operations.
We may experience downgrades in our credit ratings, which could increase our borrowing costs and potentially reduce our access to additional liquidity.

As a result of the decline in our credit ratings below investment grade in 2016, access to the commercial paper market became closed to us and we terminated our commercial paper program. So long as such access is closed, any future borrowings would have to be made under our Credit Facilities (as defined herein). Each of our Credit Facilities has a provision which changes the applicable interest rate based upon our credit ratings, and these reduced credit ratings have increased our potential interest expense for borrowings under our 2015 Credit Facility (as defined herein).
During 2016 and 2017, we experienced debt rating downgrades by Moody’s Investors Service and S&P Global Ratings, which reduced our debt ratings significantly below investment grade. As a result of these downgrades, we experienced interest rate increases during 2016 and 2017 on our Senior Notes due 2018 (the “2018 Notes”), our Senior Notes due 2025 (the “2025 Notes”) and our Senior Notes due 2045 (the “2045 Notes”), all of which are subject to provisions that vary the applicable interest rates based on our debt rating. On October 18, 2017, S&P Global Ratings further reduced our debt rating, which will increase the interest rates on the 2025 Notes and the 2045 Notes to 7.95% and 8.95%, respectively, beginning in April 2018. Once the new interest rates take effect in April 2018, these senior notes will have reached the contractually-defined maximum interest rate set for each rating agency and no further interest rate increase will occur.
Our other outstanding senior notes, including the Senior Notes due 2024 (the “2024 Notes”) issued in December 2016, and the Senior Notes due 2026 (the “2026 Notes”) issued in January 2018, do not contain provisions varying applicable interest rates based upon our credit ratings.
We are exposed to risks relating to operations in international locations.
We operate in various regions throughout the world that may expose us to political and other uncertainties, including risks of:
seizure, nationalization or expropriation of property or equipment;
monetary policies, government credit rating downgrades and potential defaults, and foreign currency fluctuations and devaluations;
limitations on the ability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;
delays in implementing private commercial arrangements as a result of government oversight;
financial or operational difficulties in complying with foreign bureaucratic actions;
changing taxation rules or policies;
other forms of government regulation and economic conditions that are beyond our control and that create operational uncertainty;
governmental corruption;
piracy; and
terrorist acts, war, revolution and civil disturbances.
Further, we operate in certain less-developed countries with legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Examples of challenges of operating in these countries include:
procedural requirements for temporary import permits, which may be difficult to obtain;
the effect of certain temporary import permit regimes, where the duration of the permit does not coincide with the general term of the drilling contract; and
ongoing claims in Brazil related to withholding taxes payable on our service contracts.

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Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. Changes in, compliance with, or our failure to comply with the laws and regulations of the countries where we operate may negatively impact our operations in those countries and could have a material adverse effect on our results of operations.
In addition, OPEC initiatives, as well as other governmental actions, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent, require partial local ownership or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.
Operating and maintenance costs of our rigs may be significant and may not correspond to revenue earned.
Our operating expenses and maintenance costs depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control. Our total operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. Equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. While operating revenues may fluctuate as a function of changes in dayrate, costs for operating a rig may not be proportional to the dayrate received and may vary based on a variety of factors, including the scope and length of required rig preparations and the duration of the contractual period over which such expenditures are amortized. Any investments in our rigs may not result in an increased dayrate for or income from such rigs. A disproportionate amount of operating and maintenance costs in comparison to dayrates could have a material adverse effect on our business, financial condition and results of operations.
Drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental clients.
Contracts with national oil companies are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our client without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. In addition, our ability to resolve disputes or enforce contractual provisions may be negatively impacted with these contracts. While we believe that the financial, commercial and risk allocation terms of these contracts and our operating safeguards mitigate these risks, we can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.
Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity.
Our business is affected by public policy and laws and regulations relating to the energy industry in the geographic areas where we operate.
The drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and accordingly, we are directly affected by the adoption of laws and regulations that for economic, environmental or other policy reasons curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases, or GHGs. This increased attention may result in new environmental laws or regulations that may unfavorably impact us, our suppliers and our customers.
The modification of existing laws or regulations or the adoption of new laws or regulations that result in the curtailment of exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons, disrupting revenue through permitting or similar delays, or subjecting us to liability.
As disclosed in Part II, Item 8, “Financial Statements and Supplementary Data, Note 14— Commitments and Contingencies,” in November 2012, the U.S. Coast Guard in Alaska conducted an inspection and investigation of the Noble Discoverer and the Kulluk, a rig we were providing contract labor services for, and referred the matters to the DOJ for further investigation. In December 2014, a subsidiary reached a settlement with the DOJ regarding its investigation of the Noble Discoverer and the Kulluk. Under the terms of the plea agreement, the subsidiary pled guilty to violations relating to maintaining proper oil record books for the Noble Discoverer and Kulluk, maintaining proper ballast records for the Noble Discoverer and notification of hazardous conditions with respect to the Noble Discoverer. The subsidiary paid $8.2 million in fines and $4 million in community service payments and implemented a comprehensive environmental compliance plan. Under the plea agreement, we were also placed on probation for four years, with the right to petition the court for early dismissal of probation after three years. We were granted our motion

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to terminate the plea agreement effective March 1, 2018. If, during the remaining term of probation, the subsidiary fails to adhere to the terms of the plea agreement, the DOJ may withdraw from the plea agreement and would be free to prosecute the subsidiary on all charges arising out of its investigation, including any charges dismissed pursuant to the terms of the plea agreement, as well as potentially other charges.
Any violation of anti-bribery or anti-corruption laws, including the Foreign Corrupt Practices Act, the United Kingdom Bribery Act, or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.
We operate in countries known to have a reputation for corruption. We are subject to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (the FCPA), the United Kingdom Bribery Act 2010 (the U.K. Bribery Act) and similar laws in other countries. Any violation of the FCPA, U.K. Bribery Act or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations.
Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
the importing, exporting, equipping and operation of drilling rigs;
currency exchange controls;
oil and gas exploration and development;
taxation of offshore earnings and earnings of expatriate personnel; and
use and compensation of local employees and suppliers by foreign contractors.
Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our rigs, our customers, our vendors or our service providers, and future changes in laws and regulations could significantly increase our costs and could have a material adverse effect on our business, financial condition and results of operations. In addition, we may be required to post additional surety bonds to secure performance, tax, customs and other obligations relating to our rigs in jurisdictions where bonding requirements are already in effect and in other jurisdictions where we may operate in the future. These requirements would increase the cost of operating in these countries, which could materially adversely affect our business, financial condition and results of operations.
In response to the Macondo well blowout incident in April 2010, the U.S. Department of Interior, through the BOEM and BSEE, began an overhaul of the offshore oil and natural gas regulatory process that significantly impacted oil and gas development regulated by the United States. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress that could materially limit or prohibit, and increase the cost of, offshore drilling. For example, in July 2016, BOEM and BSEE finalized a rule revising and adding requirements for drilling on the U.S. Arctic Outer Continental Shelf. Similarly, in April 2016, BSEE announced a final blowout preventer systems and well control rule. However, in December 2017, BSEE published a proposed rule that would revise a number of the requirements in the blowout preventer systems and well control rule. BOEM also released a new Notice to Lessees and Operators in the Outer Continental Shelf ("NTL") in September 2016 that updates offshore bonding requirements. This update eliminates waivers of supplemental bonding and prohibits a company from relying on the financial strength of co-lessees unless co-lessees agree to allocate BOEM-determined self-insurance to the lease. In January 2017, BOEM extended the implementation timeline for the NTL by six months. In May 2017, the Secretary of the Interior directed BOEM to review the NTL and provide a report describing the results of the review and options for revising or rescinding the NTL. BOEM again extended the implementation timeline for the NTL in June 2017. If the NTL goes into effect, these new bonding requirements may increase our customers’ operating costs and impact our customers’ ability to obtain leases, thereby, reducing demand for our services. We are also subject to increasing regulatory requirements and scrutiny in the North Sea jurisdictions and other countries. These new rules, regulations and requirements, including the adoption of new safety requirements and policies relating to the approval of drilling permits, restrictions on oil and gas development and production activities in the U.S. Gulf of Mexico and elsewhere, implementation of safety and environmental management systems, mandatory third party compliance audits, and the promulgation of numerous Notices to Lessees or similar new regulatory requirements outside of the United States, have impacted and may continue to impact our operations by causing increased costs, delays and operational restrictions. In addition to these rules, regulations and requirements, the U.S. federal government is considering new legislation that could impose additional equipment and safety requirements on operators and drilling contractors in the United States, as well as regulations relating to the protection of the environment. If the new regulations, policies, operating procedures and possibility of increased legal liability resulting from the adoption or amendment of rules and regulations applicable to our operations in the United States or other jurisdictions are viewed by our current or future customers as a significant

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impairment to expected profitability on projects, then they could discontinue or curtail their offshore operations in the impacted region, thereby adversely affecting our operations by limiting drilling opportunities or imposing materially increased costs.
Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, both individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
Operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of dayrates until operation of the respective drilling rig is resumed, which may lead to loss of revenue or termination or renegotiation of the drilling contract.
If our drilling rigs are idle for reasons that are not related to the ability of the rig to operate, our customers are entitled to pay a waiting, or standby, rate lower than the full operational rate. In addition, if our drilling rigs are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in our drilling contracts, we will not be entitled to payment of dayrates until the rig is able to work. Several factors could cause operational interruptions, including:
breakdowns of equipment and other unforeseen engineering problems;
work stoppages, including labor strikes;
shortages of material and skilled labor;
delays in repairs by suppliers;
surveys by government and maritime authorities;
periodic classification surveys;
inability to obtain permits;
severe weather, strong ocean currents or harsh operating conditions; and
force majeure events.
If the interruption of operations were to exceed a determined period due to an event of force majeure, our customers have the right to pay a rate that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations as described herein could materially adversely affect our business, financial condition and results of operations.
As a result of our significant cash flow needs, we may be required to incur additional indebtedness, and in the event of lost market access, may have to delay or cancel discretionary capital expenditures.
Our cash flow needs, both in the short-term and long-term, may include the following:
normal recurring operating expenses;
planned and discretionary capital expenditures; and
repayment of debt and interest.
In the future, we may require funding for capital expenditures that is beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our existing Credit Facilities. We may raise such additional capital in a number of ways, including accessing capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on terms acceptable to us or at all.
Our debt instruments could limit our operations and our debt level may limit our flexibility to obtain financing and pursue business opportunities. Our ability to obtain financing or to access the capital markets may be limited by our financial condition and our credit ratings at the time of any such financing and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, a depressed oil price, general economic conditions and uncertainties that are beyond our control. Even if we are successful in obtaining additional capital through debt financings, incurring additional indebtedness may significantly increase our interest expense and may reduce our flexibility to respond to changing business and economic conditions or to fund working capital needs, because we will require additional funds to service our outstanding indebtedness.
We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences, including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.

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We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face.
We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.
Our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by U.S. laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. Furthermore, the damage sustained to offshore oil and gas assets in the United States as a result of hurricanes has negatively impacted certain aspects of the energy insurance market, resulting in more restrictive and expensive coverage for U.S. named windstorm perils due to the price or lack of availability of coverage. Accordingly, we have in the past self-insured the rigs in the U.S. Gulf of Mexico for named windstorm perils. We currently have U.S. windstorm coverage for most of our U.S. fleet subject to limit, but will continue to monitor the insurance market conditions in the future and may decide not to, or be unable to, purchase named windstorm coverage for some or all of the rigs operating in the U.S. Gulf of Mexico.
Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so. During depressed market periods such as the one in which we currently operate, the contractual indemnity provisions we are able to negotiate in our drilling contracts may require us to assume more risk than we would during normal market periods.
Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, cyber risks, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our business, financial condition and results of operations.
Our information technology systems and those of our service providers are subject to cybersecurity risks and threats.
We depend on information technology systems that we manage, and others that are managed by our third-party service and equipment providers, to conduct our day-to-day operations, including critical systems on our drilling units, and these systems are subject to risks associated with cyber incidents or attacks. It has been reported that unknown entities or groups have mounted cyber-attacks on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Due to the nature of cyber-attacks, breaches to our service or equipment providers’ systems could go unnoticed for a prolonged period of time. These cybersecurity risks could disrupt our operations and result in downtime, loss of revenue, or the loss, theft, corruption or unauthorized release of critical data of us or those with whom we do business as well as result in higher costs to correct and remedy the effects of such incidents. If our or our service or equipment providers’ systems for protecting against cyber incidents or attacks prove to be insufficient and an incident were to occur, it could have a material adverse effect on our business, financial condition, results of operations or cash flows. Currently, we do not carry insurance for losses related to cybersecurity attacks, and may elect to not obtain such insurance in the future.
A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a material adverse effect on our financial condition and results of operations.
Income tax returns that we file will be subject to review and examination. We will not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and result in a material adverse effect on our financial condition.
Our consolidated effective income tax rate may vary substantially from one reporting period to another.
We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well

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as potential changes in UK, U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.
Our operations are subject to numerous laws and regulations relating to the protection of the environment and of human health and safety, and compliance with these laws and regulations could impose significant costs and liabilities that exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues could arise from environmental, health and safety laws and regulations covering our operations, and we may incur substantial costs and liabilities in maintaining compliance with such laws and regulations. Our operations are subject to extensive international conventions and treaties, and national or federal, state and local laws and regulations, governing environmental protection, including with respect to the discharge of materials into the environment and the security of chemical and industrial facilities. These laws govern a wide range of environmental issues, including:
the release of oil, drilling fluids, natural gas or other materials into the environment;
air emissions from our drilling rigs or our facilities;
handling, cleanup and remediation of solid and hazardous wastes at our drilling rigs or our facilities or at locations to which we have sent wastes for disposal;
restrictions on chemicals and other hazardous substances; and
wildlife protection, including regulations that ensure our activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species.
Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits, or the release of oil or other materials into the environment, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of moratoria or injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases, or could affect our relationship with certain consumers.
There is an inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our customers’ hydrocarbon products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. For example, we, as an operator of mobile offshore drilling units in navigable U.S. waters and certain offshore areas, including the U.S. Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our operations may involve the use or handling of materials that are classified as environmentally hazardous. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Joint, several or strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with past, present or future spills or releases of natural gas, oil and wastes on, under, or from past, present or future facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs. In addition, the steps we could be required to take to bring certain facilities into regulatory compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations

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themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our operations, as well as waste management and air emissions. For instance, governmental agencies could impose additional safety requirements, which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.
Finally, although some of our drilling rigs will be separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Reactivation, refurbishment, conversion or upgrades of rigs are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We will continue to make upgrades, refurbishment and repair expenditures to our fleet from time to time, some of which may be unplanned. In addition, we may reactivate rigs that have been cold or warm stacked. Our customers may also require certain shipyard reliability upgrade projects for our rigs. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
local customs strikes or related work slowdowns that could delay importation of equipment or materials;
weather interferences;
difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;
design and engineering problems;
inadequate regulatory support infrastructure in the local jurisdiction;
latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
unanticipated actual or purported change orders;
client acceptance delays;
disputes with shipyards and suppliers;
delays in, or inability to obtain, access to funding;
shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and
failure or delay of third-party equipment vendors or service providers.
The failure to complete a rig reactivation, repair, upgrade, refurbishment or new construction on time, or at all, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig reactivation, repair, upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, when our rigs are undergoing upgrade, refurbishment and repair, they may not earn a dayrate during the period they are out of service. If we experience substantial delays and cost overruns in our shipyard projects, it could have a material adverse effect on our business, financial condition and results of operations. We currently have no new rigs under construction.
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy or political or social unrest. We have limited insurance for our assets providing coverage for physical damage losses resulting from risks, such as terrorist acts, piracy, vandalism, sabotage, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenues resulting from such risks.

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Failure to attract and retain skilled personnel or an increase in personnel costs could adversely affect our operations.
We require skilled personnel to operate and provide technical services and support for our drilling units. In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. During periods of low demand, such as the one we are currently experiencing, there are layoffs of qualified personnel, who often find work with competitors or leave the industry.  As a result, once market conditions improve, we may face shortages of qualified personnel, which would impair our ability to attract qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could adversely affect our operations.

Supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations exposes us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in international markets are represented by labor unions or work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts may be made from time to time to unionize portions of our workforce. In addition, we may be subject to strikes or work stoppages and other labor disruptions in the future. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our operational flexibility.
Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
The shipment of goods, services and technology across international borders subjects our business to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions, in particular, are targeted against certain countries that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Currently, we do not, nor do we intend to, operate in countries that are subject to significant sanctions and embargoes imposed by the U.S. government or identified by the U.S. government as state sponsors of terrorism, such as the Crimean region of the Ukraine, Cuba, Iran, North Korea, Sudan and Syria. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time. Although we believe that we will be in compliance with all applicable sanctions and embargo laws and regulations at the filing date, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to significant U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.

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Pension expenses associated with our retirement benefit plans may fluctuate significantly depending upon changes in actuarial assumptions, future investment performance of plan assets and legislative or other regulatory actions.
A portion of our current and retired employee population is covered by pension and other post-retirement benefit plans, the costs of which are dependent upon various assumptions, including estimates of rates of return on benefit plan assets, discount rates for future payment obligations, mortality assumptions, rates of future cost growth and trends for future costs. In addition, funding requirements for benefit obligations of our pension and other post-retirement benefit plans are subject to legislative and other government regulatory actions. Future changes in estimates and assumptions associated with our pension and other post-retirement benefit plans could have a material adverse effect on our financial condition, results of operations, cash flows and/or financial disclosures.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
We may experience currency exchange losses when revenues are received or expenses are paid in nonconvertible currencies, when we do not hedge an exposure to a foreign currency, when the result of a hedge is a loss or if any counterparty to our hedge were to experience financial difficulties. We may also incur losses as a result of an inability to collect revenues due to a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.
We are subject to litigation that could have an adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential negative outcomes, costs of attorneys, the allocation of management’s time and attention, and other factors.
We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.
We currently conduct our operations through our subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Unless they are guarantors of our indebtedness, our subsidiaries do not have any obligation to pay amounts due on our indebtedness or to make funds available for that purpose. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may also limit our ability to obtain the cash that we require from our subsidiaries to pay our debt service obligations. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
Drilling Fleet
Noble is a leading offshore drilling contractor for the oil and gas sector. Noble owns and operates one of the most modern, versatile and technically advanced fleets of mobile offshore drilling units in the offshore drilling industry. Noble provides, through its subsidiaries, contract drilling services with a fleet of 28 offshore drilling units, consisting of eight drillships, six semisubmersibles and 14 jackups, focused largely on ultra-deepwater and high-specification drilling opportunities in both established and emerging regions worldwide. Each type of drilling rig is described further below. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and the environment of the intended drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.
Drillships
A drillship is a type of floating drilling unit that is based on the ship-based hull of the vessel and equipped with modern drilling equipment that gives it the capability of easily transitioning from various worldwide locations and carrying high capacities of equipment while being able to drill ultra-deepwater oil and gas wells in up to 12,000 feet of water. Drillships can stay directly over the drilling location without anchors in open seas using a dynamic positioning system (“DPS”), which coordinates position references from satellite signals and acoustic seabed transponders with the drillship's six to eight thrusters to keep the ship directly over the well that is being drilled. Drillships are selected to drill oil and gas wells

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for programs that require a high level of simultaneous operations, where drilling loads are expected to be high, or where there are occurrences of high ocean currents, where the drillship's hull shape is the most efficient. There are currently eight drillships in Noble's fleet, capable of water depths from 8,200 feet to 12,000 feet.
Semisubmersibles
Semisubmersible drilling units are designed as a floating drilling platform incorporating one or several pontoon hulls, which are submerged in the water to lower the center of gravity and make this type of drilling unit exceptionally stable in the open sea. Semisubmersible drilling units are generally categorized in terms of the water depth in which they are capable of operating, from the mid-water range of 300 feet to 4,000 feet, the deepwater range of 4,000 feet to 7,500 feet, to the ultra-deepwater range of 7,500 feet to 12,000 feet as well as their generation, or date of construction. This type of drilling unit typically exhibits excellent stability characteristics, providing a stable platform for drilling in even rough seas. Semisubmersible drilling units hold their position over the drilling location using either an anchored mooring system or a DPS and may be self-propelled. Noble's fleet consists of six semisubmersible drilling units, three of which are equipped with mooring systems and three of which utilize DPS, with fleet diversity to operate in mid-water, deepwater and ultra-deepwater depth ranges with high levels of efficiency.
Jackups
Noble's fleet of modern, high-specification jackup drilling units give us the flexibility to provide drilling solutions to our customers who have drilling requirements in the shallower waters of the continental shelf, in depths ranging from less than 100 feet to as deep as 500 feet. Jackup rigs can be used in open water exploration locations, as well as over fixed, bottom-supported platforms. A jackup drilling unit is a towed mobile vessel consisting of a floating hull equipped with three or four legs, which are lowered to the seabed at the drilling location. The hull is then elevated out of the water by the jacking system using the legs to support weight of the hull and drilling equipment against the seabed. Once the hull is elevated to the desired level, or jacked up, the drilling package can be extended out over an existing production platform or the open water location and drilling can commence. Noble's fleet of 14 jackups varies from three standard units capable of drilling in up to 300 feet of water to premium and high-specification units capable of drilling in up to 500 feet of water with drilling hookloads greater than 2,500,000 pounds.

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Offshore Fleet
The following table presents certain information concerning our offshore fleet at February 15, 2018. We own and operate all of the units included in the table.
Name
 
Make
 
Year Built or Rebuilt (1)
 
Water Depth Rating (feet)
 
Drilling Depth Capacity (feet)
 
Location
 
Status (2)
Drillships—8
 
 
 
 
 
 
 
 
 
 
 
 
Noble Bob Douglas
 
GustoMSC P10000
 
2013 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Active
Noble Bully I (3)
 
GustoMSC Bully PRD 12000
 
2011 N
 
8,200
 
40,000
 
Curaçao

 
Stacked
Noble Bully II (3)
 
GustoMSC Bully PRD 12000
 
2011 N
 
10,000
 
40,000
 
Singapore
 
Active
Noble Don Taylor
 
GustoMSC P10000
 
2013 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Active
Noble Globetrotter I
 
Globetrotter Class
 
2011 N
 
10,000
 
30,000
 
U.S. Gulf of Mexico
 
Active
Noble Globetrotter II
 
Globetrotter Class
 
2013 N
 
10,000
 
30,000
 
Bulgaria
 
Active
Noble Sam Croft
 
GustoMSC P10000
 
2014 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Available
Noble Tom Madden
 
GustoMSC P10000
 
2014 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Available
Semisubmersibles—6
 
 
 
 
 
 
 
 
 
 
 
 
Noble Amos Runner
 
Noble EVA-4000™
 
1999 R/2008 M
 
8,000
 
32,500
 
U.S. Gulf of Mexico
 
Stacked
Noble Clyde Boudreaux
 
F&G 9500 Enhanced Pacesetter
 
2007 R/M
 
10,000
 
35,000
 
Singapore
 
Active
Noble Danny Adkins
 
Bingo 9000-DP
 
2009 R
 
12,000
 
35,000
 
U.S. Gulf of Mexico
 
Stacked
Noble Dave Beard
 
F&G 9500 Enhanced Pacesetter-DP
 
2009 R
 
10,000
 
35,000
 
Singapore
 
Stacked
Noble Jim Day
 
Bingo 9000-DP
 
2010 R
 
12,000
 
35,000
 
U.S. Gulf of Mexico
 
Stacked
Noble Paul Romano
 
Noble EVA-4000™
 
1998 R/2007 M
 
6,000
 
25,000
 
U.S. Gulf of Mexico
 
Active
Independent Leg Cantilevered Jackups—14
 
 
 
 
 
 
 
 
 
 
Noble Alan Hay
 
Levingston Class 111-C
 
2005 R
 
300
 
25,000
 
U.A.E.
 
Stacked
Noble David Tinsley
 
Modec 300C-38
 
2010 R
 
300
 
25,000
 
U.A.E.
 
Stacked
Noble Gene House
 
Modec 300C-38
 
1998 R
 
300
 
25,000
 
Saudi Arabia
 
Active
Noble Hans Deul (4)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
U.K.
 
Active
Noble Houston Colbert (4)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Qatar
 
Active
Noble Joe Beall
 
Modec 300C-38
 
2004 R
 
300
 
25,000
 
Saudi Arabia
 
Active
Noble Lloyd Noble (4)
 
GustoMSC CJ70-x150-ST
 
2016 N
 
500
 
32,000
 
U.K.
 
Active
Noble Mick O’Brien (4)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
U.A.E.
 
Available
Noble Regina Allen (4)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
Canada
 
Active
Noble Roger Lewis (4)
 
F&G JU-2000E
 
2007 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Sam Hartley (4)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Malaysia
 
Available
Noble Sam Turner (4)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Denmark
 
Active
Noble Scott Marks (4)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Tom Prosser (4)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Australia
 
Available
(1) 
Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management. Rigs designated with an “N” are newbuilds. Rigs designated with an “M” have been upgraded to the Noble NC-5SM mooring standard.
(2) 
Rigs listed as “active” are operating, preparing to operate or under contract; rigs listed as “available” are actively seeking contracts and may include those that are idle or warm stacked; rigs listed as “shipyard” are in a shipyard for construction, repair, refurbishment or upgrade; rigs listed as “stacked” are idle without a contract and have reduced or no crew and are not actively marketed in present market conditions.
(3) 
We own and operate the Noble Bully I and Noble Bully II through joint ventures with a subsidiary of Shell. Under the terms of the joint venture agreements, each party has an equal 50 percent ownership stake in both vessels.
(4) 
Harsh environment capability.


24



Facilities
Our corporate headquarters is located in London, England. We also maintain offices in Sugar Land, Texas, where significant worldwide global support activity occurs. In addition, we own and lease operational, administrative and marketing offices, as well as other sites used primarily for operations, storage and maintenance and repairs for drilling rigs and equipment in various locations worldwide.
Item 3. Legal Proceedings.
Information regarding legal proceedings is presented in “Note 14— Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Item 4. Mine Safety Disclosures.
Not applicable.

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market for Shares and Related Shareholder Information
Noble-UK shares are listed and traded on the New York Stock Exchange under the symbol “NE.” The following table presents, for the periods indicated, the high and low sales prices and dividends or returns of capital declared and paid in U.S. Dollars per share:
 
 
High
 
Low
 
Cash Dividends Declared and Paid
2017
 
 

 
 

 
 

Fourth quarter
 
$
4.78

 
$
3.67

 
$

Third quarter
 
4.74

 
3.14

 

Second quarter
 
6.46

 
3.35

 

First quarter
 
7.80

 
5.52

 

 
 
 
 
 
 
 
2016
 
 

 
 

 
 

Fourth quarter
 
$
8.37

 
$
4.45

 
$

Third quarter
 
8.98

 
5.37

 
0.02

Second quarter
 
12.19

 
7.82

 
0.02

First quarter
 
13.90

 
6.66

 
0.16

Our most recent quarterly dividend payment to shareholders, totaling approximately $5 million (or $0.02 per share), was declared on July 22, 2016 and paid on August 8, 2016 to holders of record on August 1, 2016. Our Board of Directors eliminated our quarterly cash dividend of $0.02 per share, beginning in the fourth quarter of 2016.
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK laws. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premiums. The resumption of the payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors.
On February 20, 2018, there were 246,776,217 shares outstanding held by 215 shareholder accounts of record.
UK Tax Consequences to Shareholders of Noble-UK
The tax consequences discussed below do not reflect a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Noble. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares.

25



UK Income Tax on Dividends and Similar Distributions
A non-UK tax resident holder will not be subject to UK income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in the UK by such non-UK holder.
Disposition of Noble—UK Shares
Shareholders who are neither UK tax residents nor holding their Noble-UK shares in connection with a trade carried on through a permanent establishment in the UK will not be subject to any UK taxes on chargeable gains as a result of any disposals of their shares. Noble-UK shares held outside the facilities of The Depository Trust Company (“DTC”) should be treated as UK situs assets for the purpose of UK inheritance tax.
UK Withholding Tax—Dividends to Shareholders
Payments of dividends by Noble-UK will not be subject to any withholding in respect of UK taxation, regardless of the tax residence of the recipient shareholder.
Stamp Duty and Stamp Duty Reserve Tax in Relation to the Transfer of Shares
Stamp duty and/or stamp duty reserve tax (“SDRT”) are imposed by the UK on certain transfers of chargeable securities (which include shares in companies incorporated in the UK) at a rate of 0.5 percent of the consideration paid for the transfers in question. Certain transfers of shares to depositaries or into clearance systems are charged at a higher rate of 1.5 percent. Her Majesty’s Revenue and Customs (“HMRC”) regard DTC as a clearance system for these purposes.
Transfers of the Ordinary Shares through the facilities of DTC will not attract a charge to stamp duty or SDRT in the UK. Any transfer of title to Ordinary Shares from within those facilities to a holder outside those facilities, and any subsequent transfers that occur entirely outside those facilities, will ordinarily attract stamp duty or SDRT at a rate of 0.5 percent. This duty must be paid (and, where relevant, the transfer document stamped by HMRC) before the transfer can be registered in the books of Noble-UK. However, if those Ordinary Shares of Noble-UK are redeposited into the facilities of DTC, that redeposit will attract stamp duty or SDRT at the rate of 1.5 percent.
Share Repurchases
The Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. In December 2014, we received shareholder approval to repurchase up to 37 million ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of such shareholder approval. The authority to make such repurchases expired at the end of the Company’s 2016 annual general meeting of shareholders, which was held on April 22, 2016. During 2015, we repurchased 6.2 million of our ordinary shares covered by this authorization at an average price of $16.10 per share, excluding commissions and stamp tax, for a total cost of approximately $100.6 million. All shares repurchased were made in the open market pursuant to the share repurchase program discussed above, and all shares repurchased were immediately canceled. During the years ended December 31, 2017 and 2016, we did not repurchase any of our shares.

26



Stock Performance Graph
The chart below presents a comparison of the five-year cumulative total return, assuming $100 was invested on December 31, 2012 for Noble-UK, the Standard & Poor's 500 Index, Dow Jones U.S. Oil Equipment and Services and a self-determined offshore drillers peer group. Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date.
nenasdaqcharta01.jpg

 
 
INDEXED RETURNS
Year Ended December 31,
Company / Index
 
2013
 
2014
 
2015
 
2016
 
2017
Noble-UK
 
$
109.81

 
$
57.94

 
$
40.19

 
$
23.06

 
$
17.61

S&P 500 Index
 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

Dow Jones U.S. Oil Equipment & Services
 
128.41

 
106.29

 
82.40

 
104.91

 
87.38

Offshore Drillers Peer Group (1)
 
108.90

 
52.00

 
29.30

 
26.75

 
18.80

 

(1) 
Our self-determined peer group is weighted according to market capitalization and consists of the Company and the following peer companies: Atwood Oceanics (through October 5, 2017), Diamond Offshore Drilling Inc., Ensco plc, Rowan Companies plc, Seadrill Ltd. and Transocean Ltd.
The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

27



Item 6. Selected Financial Data.
The following table presents selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2017, which information is derived from our audited financial statements. This information should be read in conjunction with, and is qualified in its entirety by, the more detailed information in our financial statements included in Part II, Item 8 “Financial Statements and Supplementary Data,” in this Annual Report on Form 10-K.
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(In thousands, except per share amounts)
Statement of Income Data
 
 
 
 
 
 
 
 
 
 
Operating revenues from continuing operations
 
$
1,236,915

 
$
2,302,065

 
$
3,352,252

 
$
3,232,504

 
$
2,538,143

Net Income (loss) from continuing operations attributable to Noble-UK (1)
 
(516,511
)
 
(929,580
)
 
511,000

 
(152,011
)
 
478,595

Net Income (loss) from continuing operations per share attributable to Noble-UK:
 
 
 
 
 
 
 
 
 
 
Basic
 
(2.11
)
 
(3.82
)
 
2.06

 
(0.60
)
 
1.86

Diluted
 
(2.11
)
 
(3.82
)
 
2.06

 
(0.60
)
 
1.86

Balance Sheet Data (at end of period)
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
662,829

 
725,722

 
512,245

 
68,510

 
114,458

Property and equipment, net
 
9,489,240

 
10,061,948

 
11,483,623

 
12,112,509

 
14,558,090

Total assets (2)
 
10,794,659

 
11,440,117

 
12,865,645

 
13,266,480

 
16,194,639

Long-term debt (2)
 
3,795,867

 
4,040,229

 
4,162,638

 
4,848,678

 
5,532,933

Total debt (3)
 
4,045,710

 
4,340,111

 
4,462,562

 
4,848,678

 
5,532,933

Total equity
 
5,950,628

 
6,467,445

 
7,422,230

 
7,287,034

 
9,050,028

Other Data
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
453,938

 
1,126,076

 
1,764,907

 
1,778,627

 
1,708,037

Net cash used in investing activities
 
(155,588
)
 
(669,931
)
 
(432,537
)
 
(2,109,268
)
 
(2,485,107
)
Net cash provided by (used in) financing activities
 
(361,243
)
 
(242,668
)
 
(888,635
)
 
284,693

 
609,436

Capital expenditures (4)
 
111,140

 
695,925

 
422,544

 
2,072,885

 
2,487,520

Working capital (2)(5)
 
445,951

 
559,321

 
377,034

 
259,888

 
339,020

Cash distributions declared per share
 

 
0.20

 
1.28

 
1.50

 
0.76

(1) 
Results for 2017, 2016, 2015, 2014 and 2013 include impairment charges of $121.6 million, $1.5 billion, $418.3 million, $745.0 million and $3.6 million, respectively.
(2) 
Certain amounts in prior periods have been reclassified to conform to the current year presentation. In accordance with our adoption of Accounting Standard Update No. 2015-3, unamortized debt issuance costs related to our senior notes are now shown as a direct reduction of the carrying amount of the related debt. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 1— Organization and Significant Accounting Policies and Note 6— Impairment for more information.
(3) 
Consists of Long-term debt and Current maturities of long-term debt.
(4) 
Capital expenditures includes expenditures made for rigs that were ultimately transferred to Paragon Offshore as part of the Spin-off in August 2014.
(5) 
Working capital is calculated as current assets less current liabilities.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to assist you in understanding our financial position at December 31, 2017 and 2016, and our results of operations for each of the years in the three-year period ended December 31, 2017. The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the year ended December 31, 2017 filed by Noble-UK and Noble-Cayman.

28



Executive Overview
We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. As of the filing date of this Annual Report on Form 10-K, our fleet of 28 drilling rigs consisted of eight drillships, six semisubmersibles and 14 jackups strategically deployed worldwide. We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process.
Our 2017 financial and operating results from continuing operations include:
operating revenues totaling $1.2 billion;
net loss of $516.5 million, or $2.10 per diluted share, which includes a $94.8 million after-tax impairment charge recognized on three of our rigs and certain capital spare equipment; and
net cash from operating activities totaling $453.9 million.
The challenging business environment for offshore drillers continued during 2017 and into 2018. An industry-wide rig supply imbalance has remained in place, as curtailed offshore spending by customers contributed to a growing number of rigs without drilling programs. In addition, newbuild rigs ordered prior to the decline in industry activity continue to exit shipyards, while the delivery of other newbuild rigs have been delayed into the future. In either case, these rigs add to the supply imbalance. Since 2015, the industry has experienced a higher level of fleet attrition, as rigs are removed from the global supply due to a number of factors, including advanced service life, high maintenance and reactivation costs and limited customer appeal. However, the pace of attrition has been significantly less than what is required to ameliorate the capacity imbalance. In addition, our customers have adopted a cautious approach to offshore spending as crude oil prices have declined from approximately $112 per barrel for Brent crude on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to $65 per barrel on February 20, 2018. Although crude oil prices have been less volatile during 2017, we expect that the offshore drilling programs of operators will remain curtailed, until higher crude oil prices are sustained and our customers' capital spending increases. Until then, further decline in rig utilization and dayrates is possible.
We expect the business environment for the remainder of 2018 to remain challenging. The uncertainty of the viability and length of reductions in production agreed to by the Organization of Petroleum Exporting Countries (“OPEC”), the incremental production capacity in non-OPEC countries, including growing production from U.S. shale activity, the current U.S. political environment and fluid sentiment in oil markets are contributing to an uncertain oil price environment, leading to considerable uncertainty in our customers’ production spending plans. However, steady demand growth, the lack of production investments in various countries around the world and the production limits agreed to by OPEC have helped to establish market conditions supporting higher sustained crude prices recently. In general, recent contract awards have been subject to an extremely competitive bidding process. As a result, the contracts have been for dayrates that are substantially lower than rates were for the same class of rigs before this period of imbalance. We cannot give any assurances as to when conditions in the offshore drilling market will improve, or when the oversupply of available drilling rigs will end. While current market conditions persist, we will continue to focus on fleet utilization improvements, cost control initiatives and financial discipline, including the preservation of liquidity. The current business environment could lead to us stacking or retiring additional rigs.
We cannot predict the future level of demand or dayrates for our services, or future conditions in the offshore contract drilling industry. However, we believe in the long-term fundamentals for the industry and believe we are strategically well positioned during this market downturn as a result of our substantial backlog, modern fleet of high-specification rigs and strong operational capability. We also believe that these strengths will help us take advantage of any future market upcycle. Also, we expect the ultimate recovery to benefit from any sustained under-investment by customers during this current phase of the market cycle. Acceleration in customers' offshore spending, in combination with further fleet attrition, should contribute to a balanced rig supply over time.
Our business strategy focuses on a balanced, high-specification fleet of both floating and jackup rigs and the deployment of our drilling rigs in important oil and gas basins around the world.
We have expanded our drilling and fleet through our newbuild program. We took delivery of our last remaining newbuild, the heavy-duty, harsh environment jackup, the Noble Lloyd Noble, in July 2016. The Noble Lloyd Noble commenced operations in November 2016 under a four-year contract in the North Sea. Although we plan to prioritize capital preservation and liquidity based on current market conditions, from time to time we will also continue to evaluate opportunities to enhance our fleet, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required by our customers.
Spin-off of Paragon Offshore plc
On August 1, 2014, Noble-UK completed the Spin-off of a majority of its standard specification offshore drilling business through a pro rata distribution of all of the ordinary shares of its wholly-owned subsidiary, Paragon Offshore, to the holders of Noble’s ordinary shares.

29



In February 2016, Paragon Offshore sought approval of a pre-negotiated plan of reorganization (the “Prior Plan”) by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code. As part of the Prior Plan, we entered into a settlement agreement with Paragon Offshore (the “Settlement Agreement”). The Prior Plan was rejected by the bankruptcy court in October 2016.
In April 2017, Paragon Offshore filed an updated disclosure statement and a revised plan of reorganization (the “New Plan”) in its bankruptcy proceeding. Under the New Plan, including Paragon Offshore’s revised business plan, Paragon Offshore no longer needed the Mexican tax bonding that Noble-UK was to provide under the Settlement Agreement. As a result, the Settlement Agreement was no longer applicable to the ongoing business of Paragon Offshore. Consequently, Paragon Offshore abandoned the Settlement Agreement as part of the New Plan, and the Settlement Agreement was terminated at the time of the filing of the New Plan. On May 2, 2017, Paragon Offshore announced that it had reached an agreement in principle with both its secured and unsecured creditors to revise the New Plan to, among other things, create and fund a $10.0 million litigation trust to pursue litigation against us. On June 7, 2017, the revised New Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy. The complaint alleges claims of alleged actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. We continue to believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit and will be contested vigorously by us.
If any of the litigation trust’s claims are successful, or if we elect to settle any claims, any damages or other amounts we would be required to or agree to pay could have a material adverse effect on our business, financial condition and results of operations. The litigation is in the very early stages, no schedule has been established, and we are not able to predict when, or if, the matters will go to trial or otherwise be concluded. We may be required to establish reserves on our financial statements in advance of the conclusion of the litigation. Such reserves may be substantial and could have a material adverse effect on our financial condition as presented in such financial statements.
Prior to the completion of the Spin-off, Noble-UK and Paragon Offshore entered into a series of agreements to effect the separation and Spin-off and govern the relationship between the parties after the Spin-off (the “Separation Agreements”), including the Master Separation Agreement (the “MSA”) and the Tax Sharing Agreement (the “TSA”).
As part of its final bankruptcy plan, Paragon Offshore rejected the Separation Agreements. Accordingly, the indemnity obligations that Paragon Offshore potentially would have owed us under the Separation Agreements have now terminated, including indemnities arising under the MSA and the TSA in respect of obligations related to Paragon Offshore’s business that were incurred through Noble-retained entities prior to the Spin-off. Likewise, any potential indemnity obligations that we would have owed Paragon Offshore under the Separation Agreements, including those under the MSA and the TSA in respect of Noble-UK’s business that was conducted prior to the Spin-off through Paragon Offshore-retained entities, are now also extinguished. In the absence of the Separation Agreements, liabilities relating to the respective parties will be borne by the owner of the legal entity or asset at issue and neither party will look to an allocation based on the historic relationship of an entity or asset to one of the party’s business, as had been the case under the Separation Agreements.
The rejection and ultimate termination of the indemnity and related obligations under the Separation Agreements has resulted in a number of accounting charges and benefits for the year ended December 31, 2017, and such termination may continue to affect us in the future as liabilities arise for which we would have been indemnified by Paragon Offshore or would have had to indemnify Paragon Offshore. We do not expect that, overall, the rejection of the Separation Agreements by Paragon Offshore will have a material adverse effect on our financial condition or liquidity. However, any loss we experience with respect to which we would have been able to secure indemnification from Paragon Offshore under one or more of the Separation Agreements could have an adverse impact on our results of operations in any period, which impact may be material depending on our results of operations during this down-cycle.
During the year ended December 31, 2017, we recognized net charges of $15.9 million, with a non-cash loss of $1.5 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to Paragon Offshore's emergence from bankruptcy.
U.S. Federal Income Tax Reform
On December 22, 2017, the President of the United States signed into law legislation informally known as the Tax Cuts and Jobs Act (the “Act”). The Act represents major tax reform legislation that, among other provisions, reduces the U.S. corporate tax rate. For more information on the Act and its effect on our consolidated financial statements, see “—Critical Accounting Policies” and Part II, Item 8, “Note 10— Income Taxes.”


30



Impairment
As more thoroughly described in “Note 6— Impairment” to our consolidated financial statements, included in Part II, Item 8 of this Annual Report on Form 10-K, we evaluate property and equipment for impairment whenever events or changes in circumstances (including the decision to cold stack, retire or sell a rig) indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2017, 2016 and 2015, we recognized non-cash, before-tax impairment charges of $121.6 million, $1.5 billion and $418.3 million, respectively, related to certain rigs and related capital spares. These impairments were driven by factors such as customer suspensions of drilling programs, contract cancellations, a further reduction in the number of new contract opportunities, capital spare equipment obsolescence, and our belief that a drilling unit is no longer marketable and is unlikely to return to service.
There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist.
Contract Drilling Services Backlog
We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2017, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts.
We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and for the three rigs contracted with Shell mentioned below, we utilize the idle period and floor rates as described in Footnote (4) to the backlog table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.
The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
 
 
 
 
Year Ending December 31, (1)
 
 
Total
 
2018
 
2019
 
2020
 
2021
 
2022-2023
 
 
(In thousands)
Contract Drilling Services Backlog
 
 
 
 
 
 
 
 
 
 
 
 
Semisubmersibles/Drillships (2)(3)
 
$
1,881,777

 
$
504,447

 
$
400,140

 
$
381,560

 
$
338,800

 
$
256,830

Jackups (4)
 
1,077,545

 
391,041

 
304,700

 
222,963

 
116,070

 
42,771

Total (5)
 
$
2,959,322

 
$
895,488

 
$
704,840

 
$
604,523

 
$
454,870

 
$
299,601

Percent of Available Days Committed (6)
 
 
 
 
 
 
 
 
 
 
 
 
Semisubmersibles/Drillships
 
 
 
36
%
 
30
%
 
29
%
 
23
%
 
9
%
Jackups
 
 
 
53
%
 
28
%
 
19
%
 
14
%
 
3
%
Total
 
 
 
44
%
 
29
%
 
24
%
 
19
%
 
6
%

(1) 
Represents a twelve-month period beginning January 1, 2018.
(2) 
As previously reported, three of our long-term drilling contracts with Shell, the Noble Bully II, Noble Globetrotter I and Noble Globetrotter II contain a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. On December 12, 2016, we amended those drilling contracts with Shell. As a result of the amendments, each of the contracts now has a contractual dayrate floor. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide a dayrate floor of $275,000 per day. The Noble Bully II contract contains a dayrate floor of $200,000 per day plus daily operating expenses. The amendment also provided Shell the right to idle the Noble Bully II for up to one year and Noble Globetrotter II for up to two years, each at a special stacking rate. Shell has exercised its right and, beginning late December 2016, we idled the Noble Globetrotter II at a rate of $185,000 per day. The Noble Bully II was idled at a rate of $200,000 per day, effective April 3, 2017. Once the dayrate adjustment mechanism becomes effective and following any idle periods, the dayrate for these rigs will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism. The impact to contract backlog from these amendments has

31



been reflected in the table above and the backlog calculation assumes that, after any idle period at the contractual stacking rate, each rig will work at their respective dayrate floor for the remaining contract term.
(3) 
Noble and a subsidiary of Shell are involved in joint ventures that own and operate both the Noble Bully I and Noble Bully II. Pursuant to these agreements, each party has an equal 50 percent share in both vessels. As of December 31, 2017, the combined amount of backlog for these rigs totaled $515.0 million, all of which is included in backlog. Noble’s proportional interest in the backlog for these rigs totaled $257.5 million.
(4) 
Our Saudi Aramco contract rates for the Noble Joe Beall and Noble Gene House were adjusted downward in 2015. We expect the contract rates to be in the general range of the amended rates through the end of each respective contract. Backlog for these contracts has been prepared assuming the reduced rates apply for the remainder of the contract.
(5) 
Some of our drilling contracts provide the customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and financial penalties. As of February 20, 2018, no new notifications of contract terminations have been received.
(6) 
Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs and the number of calendar days in such period.
The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors— Our current backlog of contract drilling revenue may not be ultimately realized.”
For the year ended December 31, 2017, Shell, Saudi Aramco and Statoil represented approximately 57.7 percent, 18.6 percent and 14.3 percent of our backlog, respectively.
Results of Operations
2017 Compared to 2016
Net loss from continuing operations attributable to Noble-UK for the year ended December 31, 2017 was $515.0 million, or $2.10 per diluted share, on operating revenues of $1.2 billion, compared to a net loss from continuing operations for the year ended December 31, 2016 of $929.6 million, or $3.82 per diluted share, on operating revenues of $2.3 billion.
As a result of Noble-UK conducting all of its business through Noble-Cayman and its subsidiaries, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between December 31, 2017 and December 31, 2016, would be the same as the information presented below regarding Noble-UK in all material respects, with the exception of operating income (loss). During the years ended December 31, 2017 and 2016, Noble-Cayman's operating loss was $37.9 million and $29.7 million lower, respectively, than that of Noble-UK. The operating loss difference is primarily a result of administration and other costs directly attributable to Noble-UK for operations support and stewardship-related services.

32



Key Operating Metrics
Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “—Contract Drilling Services,” below. The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the years ended December 31, 2017 and 2016:
 
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
 
 
December 31,
 
December 31,
 
 
 
December 31,
 
 
 
 
2017
 
2016
 
2017
 
2016
 
% Change
 
2017
 
2016
 
% Change
Jackups
 
85
%
 
83
%
 
4,367

 
3,966

 
10
 %
 
$
126,109

 
$
126,279

 
 %
Semisubmersibles
 
17
%
 
22
%
 
365

 
649

 
(44
)%
 
155,919

 
256,122

 
(39
)%
Drillships
 
59
%
 
82
%
 
1,716

 
2,408

 
(29
)%
 
$
349,244

 
$
654,074

(3) 
(47
)%
Total
 
63
%
 
66
%
 
6,448

 
7,023

 
(8
)%
 
$
187,181

 
$
319,256

 
(41
)%
(1) 
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet, excluding newbuild rigs under construction.
(2) 
Information reflects the number of days that our rigs were operating under contract.
(3) 
Average dayrates include a $14.4 million loss in the year ended December 31, 2017 and a $14.4 million gain in the year ended December 31, 2016, in respect of the termination date valuation of certain contingent payments for the Noble Sam Croft and Noble Tom Madden related to the FCX Settlement. The loss in 2017 had a negative impact and the gain in 2016 had a positive impact on the drillships average dayrates.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the years ended December 31, 2017 and 2016 (dollars in thousands):
 
 
Year Ended December 31,
 
Change
 
 
2017
 
2016
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,207,026

 
$
2,242,200

 
$
(1,035,174
)
 
(46
)%
Reimbursables and other (1)
 
29,889

 
59,865

 
(29,976
)
 
(50
)%
 
 
$
1,236,915

 
$
2,302,065

 
$
(1,065,150
)
 
(46
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
640,489

 
$
879,438

 
$
(238,949
)
 
(27
)%
Reimbursables (1)
 
18,435

 
45,608

 
(27,173
)
 
(60
)%
Depreciation and amortization
 
524,752

 
587,999

 
(63,247
)
 
(11
)%
General and administrative
 
71,634

 
69,258

 
2,376

 
3
 %
Loss on impairment
 
121,639

 
1,458,749

 
$
(1,337,110
)
 
(92
)%
 
 
1,376,949

 
3,041,052

 
(1,664,103
)
 
(55
)%
Operating loss
 
$
(140,034
)
 
$
(738,987
)
 
$
598,953

 
(81
)%
(1) 
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.
Operating Revenues. The $1.0 billion decline in contract drilling services revenues for the year ended December 31, 2017 as compared to 2016 was composed of an $851.6 million decline from lower dayrates and a $183.6 million decline due to fewer operating days. The contract drilling services revenues decline was primarily due to our drillship and semisubmersible fleets, which experienced declines in revenues of $975.7 million and $109.3 million, respectively, and was partially offset by revenue increases in our jackup fleet of $49.8 million.
The $975.7 million revenue decline in our drillship fleet for the year ended December 31, 2017 as compared to 2016 consists of a $523.1 million decline from lower dayrates and $452.6 million decline due to fewer operating days. The decline in average dayrates was primarily related to the payment of the $393.0 million FCX Settlement in 2016. Of the decline in revenue attributable to operating days, $281.5 million is related to the Noble Bully I and Noble Bob Douglas operating for all of 2016, but being idle for the majority of 2017. The remainder of the decline in

33



operating days and the decline in average dayrates was attributable to the Noble Tom Madden and Noble Sam Croft, whose contracts were terminated in May 2016.
The $109.3 million revenue decline in our semisubmersible fleet for the year ended December 31, 2017 as compared to 2016, consists of a $36.6 million decline from lower dayrates and a $72.7 million decline due to fewer operating days. The decline in both average dayrates and operating days as compared to 2016 was attributable to contract completions for the Noble Clyde Boudreaux, Noble Jim Day, Noble Dave Beard, Noble Danny Adkins and Noble Amos Runner, none of which have returned to work since their respective contract completions.
The $49.8 million revenue increase in our jackup fleet is primarily attributable to an increase in operating days on the Noble Mick O'Brien and Noble Regina Allen as well as the startup of the newbuild Noble Lloyd Noble.
Operating Costs and Expenses. Contract drilling services costs decreased $238.9 million for the year ended December 31, 2017 as compared to 2016. Of the decrease, $179.0 million was due to rigs that operated during 2016 being idle during 2017. An additional $113.1 million decrease in cost was due to continuing cost control measures, yielding reductions in labor and training related costs of approximately $53.8 million, operations support costs of $29.7 million, repair and maintenance costs of $28.1 million, and rig mobilization costs of $3.0 million. These cost decreases were partially offset by the startup of the Noble Lloyd Noble, a greater number of operating days for contracted rigs during 2017 and the write-off of a $14.4 million customer receivable during 2017.

Depreciation and amortization decreased $63.2 million for the year ended December 31, 2017 as compared to the same period of 2016. The decline was due to the effect of rig retirements and impairments during 2016, partially offset by the effect of the Noble Lloyd Noble being placed into service during November 2016.
Other Income and Expenses
General and administrative expenses. General and administrative expenses increased $2.4 million during the year ended December 31, 2017 as compared to the same period of 2016, primarily due to higher professional fees.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $69.1 million during the year ended December 31, 2017 as compared to 2016. This increase was primarily due to the interest incurred during 2017 on the senior notes issued in December 2016, the absence of capitalized interest during 2017 and an increase in interest rates on certain of our senior notes due to the downgrading of our credit rating. These increases were partially offset by the retirement of a portion of our Senior Notes due 2020 (the “2020 Notes”), Senior Notes due 2021 (the “2021 Notes”) and Senior Notes due 2022 (the “2022 Notes”) as a result of tender offers in 2016 and the maturity of our Senior Notes due 2017 (the “2017 Notes). For additional information see, Part II, Item 8, “Financial Statements and Supplementary Data, Note 7— Debt,” to our consolidated financial statements.
Income Tax Provision. Our income tax provision increased $151.8 million for the year ended December 31, 2017 as compared to the same period of 2016. The increase was primarily due to a $260.7 million non-cash discrete tax item resulting from a tax restructuring in 2017. The effect of this tax restructuring will be to lower current tax expense. This increase was partially offset by the tax effect of the FCX contract settlement of $27.2 million in 2016. Excluding the impact of these items, taxes decreased by $86.0 million as a result of lower pre-tax income in the current year, primarily from our geographical mix of pre-tax income.
2016 Compared to 2015
Net loss from continuing operations attributable to Noble-UK for the year ended December 31, 2016 was $929.6 million, or $3.82 per diluted share, on operating revenues of $2.3 billion compared to net income from continuing operations for the year ended December 31, 2015 of $511.0 million, or 2.06 per diluted share, on operating revenues of $3.4 billion.
As a result of Noble-UK conducting all of its business through Noble-Cayman and its subsidiaries, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between December 31, 2016 and December 31, 2015, would be the same as the information presented below regarding Noble-UK in all material respects, with the exception of operating income (loss). During the year ended December 31, 2016 and 2015, Noble-Cayman's operating loss was $29.7 million lower and operating income was $28.8 million higher, respectively, than that of Noble-UK. The operating income (loss) difference is primarily a result of administration and other costs directly attributable to Noble-UK for operations support and stewardship related services.

34




Key Operating Metrics
Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “—Contract Drilling Services,” below. The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the years ended December 31, 2016 and 2015:
 
 
Average Rig Utilization (1)
 
Operating Days (2)
 
 
 
Average Dayrates
 
 
 
 
December 31,
 
December 31,
 
 
 
December 31,
 
 
 
 
2016
 
2015
 
2016
 
2015
 
% Change
 
2016
 
2015
 
% Change
Jackups
 
83
%
 
85
%
 
3,966

 
3,967

 
 %
 
$
126,279

(3) 
$
162,348

 
(22
)%
Semisubmersibles
 
22
%
 
63
%
 
649

 
1,876

 
(65
)%
 
256,122

 
445,320

 
(42
)%
Drillships
 
82
%
 
100
%
 
2,408

 
3,257

 
(26
)%
 
654,074

(4) 
547,265

(5) 
20
 %
Total
 
66
%
 
84
%
 
7,023

 
9,100

 
(23
)%
 
$
319,256

 
$
358,423

 
(11
)%
 
(1) 
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet, excluding newbuild rigs under construction.
(2) 
Information reflects the number of days that our rigs were operating under contract.
(3) 
Average dayrate for the year ended December 31, 2016 includes $16.4 million in contract drilling services revenue related to the Noble Tom Prosser contract cancellation with Quadrant Energy Australia Limited (“Quadrant”). The additional contract drilling services revenue in 2016 had a positive impact on the jackups average dayrates.
(4) 
Average dayrate for the year ended December 31, 2016 includes a gain of $14.4 million related to the termination date valuation of certain contingent payments for the Noble Sam Croft and Noble Tom Madden related to the FCX Settlement. The gain in 2016 had a positive impact on the drillships average dayrates.
(5) 
Average dayrate for the year ended December 31, 2015 includes $145.0 million in contract drilling services revenue related to the Noble Discoverer contract cancellation with Shell during 2015. The additional contract drilling services revenue in 2015 had a positive impact on the drillships average dayrates.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the years ended December 31, 2016 and 2015(dollars in thousands):
 
 
Year Ended December 31,
 
Change
 
 
2016
 
2015
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
2,242,200

 
$
3,261,610

 
$
(1,019,410
)
 
(31
)%
Reimbursables and Other (1)
 
59,865

 
88,597

 
(28,732
)
 
(32
)%
 
 
$
2,302,065

 
$
3,350,207

 
$
(1,048,142
)
 
(31
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
879,438

 
$
1,232,529

 
$
(353,091
)
 
(29
)%
Reimbursables (1)
 
45,608

 
68,182

 
(22,574
)
 
(33
)%
Depreciation and amortization
 
587,999

 
611,748

 
(23,749
)
 
(4
)%
General and administrative
 
69,258

 
76,843

 
(7,585
)
 
(10
)%
Loss on impairment
 
1,458,749

 
405,512

 
1,053,237

 
260
 %
 
 
3,041,052

 
2,394,814

 
646,238

 
27
 %
Operating income (loss)
 
$
(738,987
)
 
$
955,393

 
$
(1,694,380
)
 
(177
)%
(1) 
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.

35



Operating Revenues. The $1.0 billion decline in contract drilling services revenues for the year ended December 31, 2016 as compared to 2015 was composed of a $744.3 million decline due to fewer operating days and a $275.1 million decline from lower dayrates. The contract drilling services revenues decline was due to our semisubmersible, drillship and jackup fleets, which experienced declines in revenues of $669.0 million, $207.2 million and $143.2 million, respectively.
The $669.0 million revenue decline in our semsubmersible fleet consists of a $546.3 million decline due to fewer operating days and a $122.7 million decline from lower dayrates as compared to 2015. The declines in both operating days and average dayrates as compared to 2015 was attributable to contract completions for the Noble Jim Day, Noble Clyde Boudreaux, Noble Amos Runner, Noble Danny Adkins and Noble Dave Beard, which operated during the majority of 2015, but were not under contract in the majority of 2016.
The $207.2 million revenue decline in our drillship fleet consists of a $464.4 million decline due to fewer operating days, which was partially offset by a $257.2 million increase due to higher average dayrates as compared to 2015. The decline in operating days was primarily attributable to the retirement and subsequent sale of the Noble Discoverer, which operated in 2015 but did not operate during 2016. To a lesser extent, the decline in operating days was related to the contract cancellations of the Noble Sam Croft and Noble Tom Madden in 2016 and increased shipyard days on the Noble Globetrotter I in 2016. The revenue declines were partially offset by an increase in dayrate revenues primarily related to the occurrence of the $393.0 million FCX Settlement recognized in 2016.
The $143.2 million revenue decline in our semisubmersible fleet consists of a $143.1 million and $0.1 million decline due to a decrease in average dayrates and fewer operating days, respectively, as compared to 2015. The decrease in average dayrates was primarily attributable to the Noble Regina Allen, which was not operating under a contract during the majority of 2016 but operated during 2015, the retirement and subsequent sale of the Noble Charles Copeland, which operated during 2015, and the Noble Houston Colbert, which completed its contract during 2016. The revenue decreases were partially offset by the commencement of the newbuilds, the Noble Sam Hartley and Noble Lloyd Noble, which commenced operations in January 2016 and November 2016, respectively.
Operating Costs and Expenses. Contract drilling services costs decreased $353.1 million for the year ended December 31, 2016 as compared to 2015. Of the decrease, $254.5 million was due to rigs that operated during 2015, but were idle during 2016. An additional $95.2 million decline in cost was due to the retirement of the Noble Discoverer, Noble Charles Copeland and Noble Max Smith. An additional $62.1 million decline was due to continuing cost control measures. The cost control measures yielded reductions in repair and maintenance costs of $21.4 million, labor and training related costs of $19.9 million, operations support costs of approximately $8.1 million and other rig-related costs of $12.7 million. This was partially offset by a $58.7 million increase in cost related to rigs that had additional operating days during 2016, including two newbuild rigs, which commenced operations during 2016.
Loss on impairment during 2016 of $1.5 billion was recognized after we identified indicators that the carrying value of certain assets in our fleet may not be recoverable. As a result of our analysis, we determined that the carrying amounts of certain drilling units were impaired. In connection with our annual analysis, we impaired the carrying values for the Noble Amos Runner, Noble Clyde Boudreaux and Noble Dave Beard to the fair value. The impairment charge related to these units was approximately $1.0 billion. We also decided to retire from service our semisubmersible, the Noble Max Smith, which we sold during the fourth quarter of 2016 for approximately $1.2 million, and we recognized an impairment charge of approximately $164.8 million.
Also, in the fourth quarter of 2016, in connection with our impairment analysis, we concluded that the semisubmersible, the Noble Homer Ferrington and certain capital spare equipment would not be utilized in the foreseeable future and we recognized an impairment charge of approximately $120.1 million and $153.9 million, respectively. In the second quarter of 2016, we recognized a charge of approximately $16.6 million for the impairment of certain capital spare equipment based upon our decision to dispose of this equipment.
Other Income and Expenses
General and administrative expenses. General and administrative expenses decreased $7.6 million during 2016 as compared to 2015, primarily as a result of decreased employee-related costs.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $9.1 million during 2016 as compared to 2015. The increase was a result of a full period of interest in respect of the senior notes issued in March 2015, an increase in applicable interest rates on those senior notes due to the downgrading of our credit rating below investment grade during 2016 and lower capitalized interest in 2016 as compared to 2015, due to the completion of construction of two newbuild jackups, the Noble Sam Hartley and Noble Lloyd Noble, which commenced their respective contracts in January 2016 and November 2016. During 2016, we capitalized approximately 9 percent of total interest charges versus approximately 10 percent during the prior year. These expense increases were partially offset by the repayment of our maturing $350 million 3.45% Senior Notes due 2015 and our $300 million 3.05% Senior Notes due 2016 in August 2015 and March 2016, respectively, and the retirement of a portion of the 2020 Notes, the 2021 Notes and the 2022 Notes as a result of two different tender offers during 2016.

36



Interest Income and Other, Net. Interest income and other, net, decreased $36.3 million during 2016 as compared to 2015. The decrease is primarily the result of the prior year including $30.0 million of interest income recognized in connection with the Noble Homer Ferrington arbitration award and $5.0 million of interest received on a U.S. Internal Revenue Service (“IRS”) tax refund for the years 2006 and 2007.
Gain on extinguishment of debt, net. Gain on debt extinguishment increased $18.0 million during the year ended December 31, 2016 as compared to 2015. This increase is due to the completion of cash tender offers on our 2020 Notes, 2021 Notes and 2022 Notes during 2016, resulting in the purchase of $798.0 million of these senior notes for $774.0 million, plus accrued interest.
Income Tax Benefit (Provision). Our income tax provision decreased $268.0 million in 2016, of which $126.0 million related to the impact of impairment charges recognized in 2016, the Quadrant contract cancellation payment, the FCX Settlement, retirement of a portion of our 2020 Notes, 2021 Notes and 2022 Notes as a result of tender offers and discrete tax items in the current year and $27.0 million related to the Noble Homer Ferrington arbitration award in 2015. Excluding the impact of these items, taxes decreased by $115.0 million as a result of lower pre-tax income partially offset by a higher effective tax rate in the current year, primarily from our geographical mix of pre-tax income.
Liquidity and Capital Resources
Overview
Net cash provided by operating activities was $453.9 million for the year ended December 31, 2017 and $1.1 billion for the year ended December 31, 2016. The decrease in net cash provided by operating activities for the year ended December 31, 2017 was primarily attributable to a reduction in operating activity during 2017. We had working capital of $446.0 million and $559.3 million at December 31, 2017 and December 31, 2016, respectively.
Net cash used in investing activities for the year ended December 31, 2017 was $155.6 million as compared to $669.9 million for the year ended December 31, 2016. The variance primarily relates to lower capital expenditures related to our major projects and newbuild expenditures in the current period.
Net cash used in financing activities for the year ended December 31, 2017 was $361.2 million as compared to $242.7 million for the year ended December 31, 2016. During the current period, our primary uses of cash included the repayment of the 2017 Notes for $300.0 million and dividends paid to noncontrolling interests of approximately $56.9 million.
Our principal source of capital in the current period was cash generated from operating activities and cash on hand. Cash on hand during the current period was primarily used for the following:
normal recurring operating expenses;
repayment of the 2017 Notes; and
capital expenditures.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
normal recurring operating expenses;
planned and discretionary capital expenditures; and
repayment of debt and interest.
We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our Credit Facilities (as defined below) and potential issuances of long-term debt. However, to adequately cover our expected cash flow needs, we may require capital in excess of the amount available from these sources, and we may seek additional sources of liquidity and/or delay or cancel certain discretionary capital expenditures or other payments as necessary.
At December 31, 2017, we had a total contract drilling services backlog of approximately $3.0 billion. Our backlog as of December 31, 2017 includes a commitment of 44 percent of available days for 2018. For additional information regarding our backlog, see “—Contract Drilling Services Backlog.”
Capital Expenditures
Capital expenditures, including capitalized interest, totaled $111.1 million, $659.9 million and $422.5 million for the years ended December 31, 2017, 2016 and 2015 respectively. Capital expenditures during 2017 consisted of the following:
$58.6 million for sustaining capital and upgrades and replacements to drilling equipment;
$39.3 million in major projects; and
$13.2 million in subsea related expenditures.
Our total capital expenditure estimate for 2018 is approximately $148.0 million, which is currently anticipated to be spent as follows:
$83.0 million for sustaining capital; and

37



$65.0 million for major projects, subsea related expenditures and upgrades and replacements to drilling equipment.
From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements and changes in design criteria or specifications during repair or construction.
Dividends
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK laws. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premiums. The resumption of the payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors.
Share Repurchases
The Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. In December 2014, we received shareholder approval to repurchase up to 37 million ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of the shareholder approval. The authority to make such repurchases expired at the end of the Company’s 2016 annual general meeting of shareholders, which was held on April 22, 2016. During 2015, we repurchased 6.2 million of our ordinary shares covered by this authorization at an average price of $16.10 per share, excluding commissions and stamp tax, for a total cost of approximately $100.6 million. All shares repurchased were made in the open market pursuant to the share repurchase program discussed above, and all shares repurchased were immediately canceled. During the years ended December 31, 2017 and 2016, we did not repurchase any shares of our shares.
Credit Facilities and Senior Unsecured Notes
2015 Credit Facility
At December 31, 2017, we had a five-year $2.4 billion senior unsecured credit facility that matures in January 2020 and which is guaranteed by our indirect, wholly owned subsidiaries, Noble Holding (U.S.) LLC (“NHUS”) and Noble Holding International Limited (“NHIL”) (the “2015 Credit Facility”). The 2015 Credit Facility also provided us with the ability to issue up to $500.0 million in letters of credit. The issuance of letters of credit under the facility reduces the amount available for borrowing. At December 31, 2017, we had no borrowings outstanding or letters of credit issued under our 2015 Credit Facility.
On December 19, 2017, we entered into the First Amendment and Consent and Successor Agent Agreement, (the “Amendment”) amending the 2015 Credit Facility. Upon certain conditions, including the entering into of the Company's 2017 Credit Facility (as defined below), the Amendment provides for, on or after January 3, 2018, among other things (i) a reduction in the aggregate principal amount of commitments under the 2015 Credit Facility to $300.0 million and (ii) the reduction of the 2015 Credit Facility's letter of credit subfacility to zero dollars. The maturity of the 2015 Credit Facility remains January 2020.
2017 Credit Facility
On December 21, 2017, Noble Cayman Limited, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman (“NCL”); Noble International Finance Company (“NIFCO“); and Noble Holding UK Limited, a company incorporated under the laws of England and Wales and a wholly-owned direct subsidiary of Noble-UK (“NHUK”), as parent guarantor, entered into a new senior unsecured credit agreement (the “2017 Credit Facility” and together with the 2015 Credit Facility, the “Credit Facilities“). The maximum aggregate amount of borrowings under the 2017 Credit Facility of $1.5 billion became available on January 3, 2018 upon the effectiveness of the commitment reduction under the 2015 Credit Facility. Borrowings under the 2017 Credit Facility are subject to certain conditions precedent, including that there be no unused commitments to advance loans under the 2015 Credit Facility. The 2017 Credit Facility provides for a letter of credit subfacility currently in the amount of $15.0 million, with the ability to increase such amount up to $500.0 million. Borrowings may be used for working capital and other general corporate purposes. The 2017 Credit Facility has an initial maturity of up to five years from the date on which the borrowings became available, or January 3, 2023. At December 31, 2017, we had no borrowings outstanding or letters of credit issued under the 2017 Credit Facility.

Both of our Credit Facilities have provisions which vary the applicable interest rates for borrowings based upon our debt ratings. We also pay a facility fee under each of the Credit Facilities on the daily unused amount of the underlying commitment which varies depending on our

38



credit ratings. At December 31, 2017, the interest rates in effect under our Credit Facilities are the highest permitted interest rates under those agreements.
Debt Issuances
On January 31, 2018, we issued and sold $750.0 million aggregate principal amount of our Senior Notes due 2026 (the “2026 Notes”), through our indirect wholly-owned subsidiary, NHIL. The 2026 Notes are issued under an indenture by and among NHIL, Noble-Cayman, certain other subsidiaries of Noble-Cayman named therein (the “Subsidiary Guarantors”), and are guaranteed by Noble-Cayman and the Guarantor Subsidiaries. The proceeds of the offering of approximately $737.0 million, after estimated expenses, were used to retire a portion of our near-term senior notes in a related tender offer.
The 2026 Notes are redeemable, in whole or in part, prior to February 1, 2021, at a redemption price equal to 100% of the aggregate principal amount of the 2026 Notes being redeemed, plus a make-whole premium. The 2026 Notes are redeemable prior to February 1, 2021, at a redemption price equal to 40% of the aggregate principal amount in the event of an equity offering. Further, the 2026 Notes may be redeemed in whole as a result of changes in tax law. On or after February 1, 2021, we may redeem all or any portion of the 2026 Notes at various redemption prices set forth in the indenture.
Upon (i) the occurrence of a change of control and (ii) a downgrade of the rating of the 2026 Notes within 60 days after the change of control by at least two of Moody’s Investors Service, Inc., Standard & Poor’s Financial Services LLC or Fitch Ratings Inc., we will be required to make an offer to repurchase all outstanding 2026 Notes at a price in cash equal to 101% of the aggregate principal amount of the 2026 Notes repurchased, plus any accrued and unpaid interest to, but excluding, the repurchase date.
The indenture for the 2026 Notes contains certain covenants and restrictions, including, among others, restrictions on our and our subsidiaries’ ability, as applicable, to create certain liens, enter into certain sale and leaseback transactions, merge or consolidate with another entity, sell all or substantially all of their assets and allow our subsidiaries to incur certain additional indebtedness. Additionally, the Subsidiary Guarantors must own, directly or indirectly, (i) assets comprising at least 85%of the revenue of Noble-Cayman and its subsidiaries on a consolidated basis and (ii) jackups, semisubmersibles, drillships, submersibles or other mobile offshore drilling units of material importance, the combined book value of which comprises at least 85% of the combined book value of all such assets of Noble-Cayman and its subsidiaries on a consolidated basis, in each case, with respect to the most recently completed fiscal year.
In December 2016, we issued $1.0 billion aggregate principal amount of Senior Notes due 2024 (the “2024 Notes”), which we issued through our indirect wholly-owned subsidiary, NHIL. The net proceeds of approximately $967.6 million, after estimated expenses, were primarily used to retire a portion of our near-term senior notes in a related tender offer and the remaining portion was used for general corporate purposes.
Senior Notes Interest Rate Adjustments
During 2016 and 2017, we experienced debt rating downgrades by Moody’s Investors Service and S&P Global Ratings, which reduced our debt ratings significantly below investment grade. As a result of these downgrades, we experienced interest rate increases during 2016 and 2017 on the 2018 Notes, the 2025 Notes and the 2045 Notes, all of which are subject to provisions that vary the applicable interest rates based on our debt rating. On October 18, 2017, S&P Global Ratings further reduced our debt rating, which will increase the interest rates on the 2025 Notes and the 2045 Notes to 7.95% and 8.95%, respectively, beginning in April 2018. Once the new interest rates take effect in April 2018, these senior notes will have reached the contractually-defined maximum interest rate set for each rating agency and no further interest rate increase will occur
Our other outstanding senior notes, including the 2024 Notes issued in December 2016 and the 2026 Notes issued in January 2018, do not contain provisions varying applicable interest rates based upon our credit ratings.
Debt Tender Offers and Repayments
In January 2018, we commenced cash tender offers for our 2018 Notes, 2019 Notes, 2020 Notes, 2021 Notes, 2022 Notes and 2024 Notes. In February 2018, we purchased $754.2 million aggregate principal amount of these senior notes for $750.0 million, plus accrued interest, using the net proceeds of the 2026 Notes issuance in January 2018 and cash on hand. As a result of these tender offers, we recognized a net loss of approximately $2.0 million. In February 2018, we completed an optional redemption of our remaining 2019 Notes. Both the tender offers and redemption are described further in “Note 19— Subsequent Events.”
In March 2017, we repaid our 2017 Notes using cash on hand. We anticipate using cash on hand to repay the outstanding balance of our 2018 Notes, maturing in March 2018.
In December 2016, we commenced cash tender offers for our 2020 Notes, 2021 Notes and 2022 Notes. On December 28, 2016, we purchased $762.3 million of these senior notes for $750.0 million, plus accrued interest, using a portion of the net proceeds of the $1.0 billion 2024 Notes issuance in December 2016. In December 2016, as a result of these tender offers, we recognized a net gain of approximately $6.7 million.

39



In March 2016, we commenced cash tender offers for our 2020 Notes and our 2021 Notes. On April 1, 2016, we purchased $36.0 million of these senior notes for $24.0 million, plus accrued interest, using cash on hand. In April 2016, as a result of these tender offers, we recognized a net gain of approximately $11.1 million.
Covenants
The 2015 Credit Facility is guaranteed by NHUS and NHIL. The 2015 Credit Facility contains a covenant that limits our ratio of debt to total tangible capitalization, as defined in the 2015 Credit Facility, to 0.60. At December 31, 2017, our ratio of debt to tangible capitalization was approximately 0.43.
The 2017 Credit Facility contains certain financial covenants (as defined in the 2017 Credit Facility) applicable to NHUK and its subsidiaries, including (i) a covenant restricting debt to total tangible capitalization to not greater than 55% at the end of each fiscal quarter, (ii) a minimum Liquidity requirement of $300.0 million, (iii) a covenant that, beginning with the fiscal quarter ending March 31, 2018, the ratio of the Rig Value of Marketed Rigs to the sum of commitments under the 2017 Credit Facility plus indebtedness for borrowed money of the borrowers and guarantors, in each case, that directly own Marketed Rigs, is not less than 3:00 to 1:00 at the end of each fiscal quarter and (iv) a covenant that, beginning with the fiscal quarter ending March 31, 2018, the ratio of (A) the Rig Value of the Closing Date Rigs that are directly wholly owned by the borrowers and guarantors to (B) the Rig Value of the Closing Date Rigs owned by NHUK, subsidiaries of NHUK and certain local content affiliates, is not less than 80% at the end of each fiscal quarter (such covenants described in (iii) and (iv) of this paragraph, the “Guarantor Ratio Covenants”). The 2017 Credit Facility also includes restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of Available Cash (as defined in the 2017 Credit Facility) would exceed $200.0 million.
NHUK has guaranteed the obligations of the borrowers under the 2017 Credit Facility. Certain other subsidiaries of Noble-UK will be required from time to time to guarantee the obligations of the borrowers under the 2017 Credit Facility in order maintain compliance with the Guarantor Ratio Covenants.
The 2017 Credit Facility contains additional covenants generally applicable to NHUK and its subsidiaries that NCL considers usual and customary for an agreement of this type, including compliance with laws (including environmental laws, ERISA and anti-corruption and sanctions laws), delivery of quarterly and annual financial statements, maintenance and operation of property, restrictions on the incurrence of liens and indebtedness, mergers and other fundamental changes, restricted payments, repurchases and redemptions of indebtedness with maturities outside of the maturity of the 2017 Credit Facility, sale and leaseback transactions and transactions with affiliates. Borrowings under the 2017 Credit Facility are subject to acceleration upon the occurrence of events of default that NCL considers usual and customary for an agreement of this type.
In addition to the covenants from the Credit Facilities noted above, the indentures governing our outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. In addition, there are restrictions on incurring debt or assuming certain liens and on entering into sale and lease-back transactions. The indenture for the 2026 Notes that we issued in January 2018 places more limitations on us and our subsidiaries than our other senior note indentures. See “—Debt Issuances” above.
At December 31, 2017, and February 20, 2018, we were in compliance with all of the debt covenants under our Credit Facilities and senior notes. We continually monitor compliance with the covenants under our Credit Facilities and senior notes and expect to remain in compliance during the remainder of 2018.

40



Summary of Contractual Cash Obligations and Commitments
The following table summarizes our contractual cash obligations and commitments (in thousands):
 
 
 
 
Payments Due by Period
 
 
 
 
 
 
For the years ending December 31,
 
 
 
 
Total
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Other
Contractual Cash Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt obligations
 
$
4,103,797

 
$
250,000

 
$
201,695

 
$
167,766

 
$
208,675

 
$
125,661

 
$
3,150,000

 
$

Interest payments
 
3,525,623

 
264,221

 
249,270

 
242,735

 
229,898

 
224,345

 
2,315,154

 

Operating leases
 
42,609

 
18,720

 
14,046

 
2,564

 
1,853

 
1,586

 
3,840

 

Pension plan contributions
 
145,613

 
12,623

 
12,093

 
12,643

 
16,778

 
15,890

 
75,586

 

Tax reserves (1)
 
191,860

 

 

 

 

 

 

 
191,860

Total contractual cash obligations
 
$
8,009,502

 
$
545,564

 
$
477,104

 
$
425,708

 
$
457,204

 
$
367,482

 
$
5,544,580

 
$
191,860

(1) 
Tax reserves are included in “Other” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See “Note 10— Income Taxes” to our accompanying consolidated financial statements.
At December 31, 2017, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit obligations are not normally called, as we typically comply with the underlying performance requirement.
The following table summarizes our other commercial commitments at December 31, 2017 (in thousands):
 
 
 

 
Amount of Commitment Expiration Per Period
 
 
Total
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
Total letters of credit and commercial commitments
 
$
7,846

 
$
2,231

 
$
2,038

 
$
25

 
$

 
$

 
$
3,552

Critical Accounting Policies
We consider the following to be our critical accounting policies and estimates since they are very important to the understanding of our financial condition and results and require our most subjective and complex judgments.  We have discussed the development, selection and disclosure of such policies and estimates with the Audit Committee of our Board of Directors.  For a discussion of our significant accounting policies, refer to Part II, Item 8, “Note 1— Organization and Significant Accounting Policies.”
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the U.S. (“GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities.  These estimates require significant judgments and assumptions.  We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates.
Principles of Consolidation
The consolidated financial statements include our accounts, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. Our consolidated financial statements include the accounts of two joint ventures, in each of which we own a 50 percent interest. Our ownership interest meets the definition of variable interest under Financial Accounting Standards Board (“FASB”) codification and we have determined that we are the primary beneficiary. Intercompany balances and transactions have been eliminated in consolidation.
The combined carrying amount of the Bully-class drillships at December 31, 2017 and 2016 totaled $1.3 billion and $1.4 billion, respectively. These assets were primarily funded through partner equity contributions. Cash held by the Bully joint ventures totaled approximately $41.6 million at December 31, 2017 as compared to approximately $34.7 million at December 31, 2016.
Basis of Presentation-U.K. Companies Act 2006 Section 435 Statement
The accompanying consolidated financial statements have been prepared in accordance with US GAAP, which the Board of Directors consider to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the UK Companies Act 2006 (“Companies Act”), which will be prepared in accordance

41



with International Financial Reporting Standards, as adopted by the European Union and delivered to the Registrar of Companies in the UK following the annual general meeting of shareholders.
Property and Equipment
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. At December 31, 2017 and 2016, we had $83.5 million and $112 million of construction-in-progress, respectively. Such amounts are included in “Property and equipment, at cost” in the accompanying Consolidated Balance Sheets. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to forty years.
Interest is capitalized on construction-in-progress using the weighted average cost of debt outstanding during the period of construction. During the year ended December 31, 2017, there was no capitalized interest due to the completion of our newbuild program. Capitalized interest was $22.4 million and $25.0 million for the years ended December 31, 2016 and 2015, respectively.
Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in the Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $149.3 million and $187.0 million at December 31, 2017 and 2016, respectively. Depreciation expense from continuing operations related to overhauls and asset replacement totaled $79.2 million, $86.0 million and $75.0 million for the years ended December 31, 2017, 2016 and 2015, respectively.
We evaluate the impairment of property and equipment whenever events or changes in circumstances (including the decision to cold stack, retire or sell a rig) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset's carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2017, 2016 and 2015 we recognized a non-cash loss on impairment of $121.6 million, $1.5 billion, and $418.3 million, respectively, related to our long-lived assets. See Part II, Item 7, “Management Discussion and Analysis— Executive Overview,” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 6— Impairment,” for additional information.

Revenue Recognition
Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate-basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned, and when collectability is reasonably assured.
In our dayrate drilling contracts, we typically receive compensation and incur costs for mobilization, equipment modification or other activities prior to the commencement of a contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized, using the straight-line method, into income or loss over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.
Deferred revenues from drilling contracts totaled $114.3 million and $134.4 million at December 31, 2017 and 2016, respectively. Such amounts are included in either “Other current liabilities” or “Other liabilities” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition. Related expenses deferred under drilling contracts totaled $55.7 million at December 31, 2017 as compared to $72.8 million at December 31, 2016 and are included in either “Prepaid expenses and other current assets,” “Other assets,” or “Property and equipment, net” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.

42



In April 2015, we agreed to contract dayrate reductions for five rigs working for Saudi Aramco. Given current market conditions and based on discussions with the customer, we do not expect the rates for the rigs currently working for Saudi Aramco to return to the original contract rates during the remaining contract terms. In accordance with accounting guidance, we are recognizing the rate reductions on a straight-line basis over the remaining life of these Saudi Aramco contracts. At December 31, 2017 and 2016, two of the five original rigs had revenues recorded in excess of billings as a result of this recognition which totaled $6.9 million and $17.9 million, respectively, and are included in either “Prepaid expenses and other current assets” or “Other assets” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
Income Taxes
We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. Our net deferred tax asset balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. The company has adopted an accounting policy to look through the outside basis of partnerships and all other flow-through entities and exclude these from the computation of deferred taxes.
During 2014, the IRS began its examination of our tax reporting in the U.S. for the taxable years ended December 31, 2010 and 2011. The IRS examination team has completed its examination of our 2010 and 2011 U.S. tax returns and proposed adjustments and deficiencies with respect to certain items that were reported by us for the 2010 and 2011 tax years. On December 19, 2016, we received the Revenue Agent Report (“RAR”) from the IRS. We believe that we have accurately reported all amounts in our tax returns, and have submitted administrative protests with the IRS Office of Appeals contesting the examination team’s proposed adjustments. We intend to vigorously defend our reported positions, and believe the ultimate resolution of the adjustments proposed by the IRS examination team will not have a material adverse effect on our consolidated financial statements. During the third quarter of 2017, the IRS initiated its examination of our 2012, 2013, 2014 and 2015 tax returns.
In previous periods, we reported that Mexican and Brazilian authorities had made significant tax assessments against Paragon Offshore entities, a portion of which related to Noble’s business that operated through Paragon Offshore-retained entities in Mexico and Brazil prior to the Spin-off. As a result of the termination of the Separation Agreements, we no longer have any indemnity obligations in respect of these tax claims made against Paragon Offshore entities, and responsibility for these claims has reverted back to the applicable Paragon Offshore entity. Audit claims of approximately $48.3 million attributable to income and other business taxes have been assessed against Noble entities in Mexico.
In previous periods, we also reported that Petrobras had notified us that it was challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during 2008 and 2009. Petrobras had also notified us that if Petrobras was ultimately forced to pay such withholding taxes, it would seek reimbursement from Paragon Offshore who would then seek reimbursement from us for the portion of the withholding that was allocable to our drilling rigs. As a result of the termination of the Separation Agreements, we no longer have any indemnity obligation in respect of these withholding claims made against a Paragon Offshore entity, and responsibility for these claims has reverted back to the applicable Paragon Offshore entity.
On December 22, 2017, the President of the United States signed the into law legislation informally known as the Tax Cuts and Job Act (the “Act”). The Act represents major tax reform legislation that, among other provisions, reduces the U.S. corporate tax rate. The Company recognized the income tax effects of the Act in its 2017 financial statements, including $109.0 million of tax benefit recorded principally due to the write-down of our net deferred tax liabilities, in accordance with Accounting Standards Codification ("ASC") Topic 740, Income Taxes, in the reporting period in which the Act was enacted. Based on guidance issued from Staff Accounting Bulletin No. 118 ("SAB 118"), the Company has not provided provisional estimates for items in which the accounting for certain income tax effects of the Act is incomplete and as such, the Company will continue to apply ASC 740 on the basis of the laws in effect immediately before the enactment of the Act. For more information on the Act and its effect on our consolidated financial statements, see Part II, Item 8, “Note 10— Income Taxes.”
The Act introduces a new anti-deferral provision, which subjects a U.S. parent shareholder to current tax on certain income referred to as Global Intangible Low-Taxed Income (“GILTI”), of its foreign subsidiaries. The company has not made any adjustments related to potential GILTI tax in its financial statements and has adopted a policy to treat tax due on future U.S. inclusions in taxable income as period costs when incurred.
Insurance Reserves
We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.
Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and

43



circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. At December 31, 2017 and 2016, loss reserves for personal injury and protection claims totaled $22.0 million and $22.1 million, respectively, and such amounts are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We follow FASB standards regarding contingent liabilities, which are discussed in Part II, Item 8, "Financial Statements and Supplementary Data, “Note 14— Commitments and Contingencies.”
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
New Accounting Pronouncements
See Part II, Item 8, “Financial Statements and Supplementary Data, Note 1— Organization and Significant Accounting Policies,” to the Consolidated Financial Statements for a description of the recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Market risk is the potential for loss due to a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on borrowings under the Credit Facilities. Interest on borrowings under our Credit Facilities is at an agreed upon percentage point spread over LIBOR, or a base rate stated in the agreements. At December 31, 2017, we had no borrowings outstanding under our Credit Facilities.
During 2017 and 2016, we experienced debt rating downgrades by Moody’s Investors Service and S&P Global Ratings, which reduced our debt ratings significantly below investment grade. As a result of these downgrades, we experienced interest rate increases during 2017 and 2016 on the 2018 Notes, 2025 Notes and 2045 Notes, all of which are subject to provisions that vary the applicable interest rates based on our debt rating. On October 18, 2017 S&P Global Ratings further reduced our debt rating, which will increase the interest rates on the 2025 Notes and 2045 Notes to 7.95% and 8.95%, respectively, beginning in April 2018. Once the new interest rates take effect in April 2018, these senior notes will have reached the contractually-defined maximum interest rate set for each rating agency and no further interest rate increase will occur.
Our other outstanding senior notes, including the 2024 Notes issued in December 2016, and 2026 Notes issued in January 2018, do not contain provisions varying applicable interest rates based upon our credit ratings.
We maintain certain debt instruments at a fixed rate whose fair value will fluctuate based on changes in market expectations for interest rates and perceptions of our credit risk. The fair value of our total debt was $3.4 billion and $3.8 billion at December 31, 2017 and December 31, 2016, respectively. The decrease in the fair value of debt relates to the maturity of our 2017 Notes and changes in market expectations for interest rates and perceptions of our credit risk.
Foreign Currency Risk
Although we are a UK company, we define foreign currency as any non-U.S. denominated currency. Our functional currency is primarily the U.S. Dollar, which is consistent with the oil and gas industry. However, outside the United States, a portion of our expenses are incurred in local currencies. Therefore, when the U.S. Dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in U.S. Dollars will increase (decrease).
We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currency that are other than the functional currency. To help manage this potential risk, we periodically enter into derivative instruments to manage our exposure to fluctuations in currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are

44



primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the Consolidated Balance Sheet and in “Accumulated other comprehensive income (loss)” (“AOCI”). Amounts recorded in AOCI are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Several of our regional shorebases, including our North Sea operations, have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we periodically enter into forward contracts, which settle monthly in the operations’ respective local currencies. All of these contracts have a maturity of less than 12 months. During 2017 and 2016, we entered into forward contracts of approximately $37.6 million and $53.1 million, respectively, all of which settled during their respective years. At both December 31, 2017 and 2016, we had no outstanding derivative contracts.
Market Risk
We have a U.S. noncontributory defined benefit pension plan that covers certain salaried employees and a U.S. noncontributory defined benefit pension plan that covers certain hourly employees, whose initial date of employment is prior to August 1, 2004 (collectively referred to as our “qualified U.S. plans”). These plans are governed by the Noble Drilling Employees’ Retirement Trust. The benefits from these plans are based primarily on years of service and, for the salaried plan, employees’ compensation near retirement. These plans are designed to qualify under the Employee Retirement Income Security Act of 1974 (“ERISA”), and our funding policy is consistent with funding requirements of ERISA and other applicable laws and regulations. We make cash contributions, or utilize credits available to us, for the qualified U.S. plans when required. The benefit amount that can be covered by the qualified U.S. plans is limited under ERISA and the Internal Revenue Code (“IRC”) of 1986. Therefore, we maintain an unfunded, nonqualified excess benefit plan designed to maintain benefits for specified employees at the formula level in the qualified salary U.S. plan. We refer to the qualified U.S. plans and the excess benefit plan collectively as the “U.S. plans.”
In addition to the U.S. plans, each of Noble Drilling (Land Support) Limited and Noble Resources Limited, both indirect, wholly-owned subsidiaries of Noble-UK, maintains a pension plan that covers all of its salaried, non-union employees, whose most recent date of employment is prior to April 1, 2014 (collectively referred to as our “non-U.S. plans”). Benefits are based on credited service and employees’ compensation, as defined by the plans.
Changes in market asset values related to the pension plans noted above could have a material impact upon our Consolidated Statement of Comprehensive Income (Loss) and could result in material cash expenditures in future periods.

45



Item 8. Financial Statements and Supplementary Data.
The following financial statements are filed in this Item 8: 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Shareholders of Noble Corporation plc

Opinions on the Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Noble Corporation plc and its subsidiaries (the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and equity for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control Over Financial Reporting as appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
February 23, 2018

We have served as the Company’s auditor since 1994.  


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NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)

 
 
December 31,
2017
 
December 31,
2016
ASSETS
Current assets
 
 
 
 
Cash and cash equivalents
 
$
662,829

 
$
725,722

Accounts receivable, net